Acknowledgments
This report was made possible through support from the Oregon Community Foundation. The
opinions and recommendations expressed in this report are those of the author and do not
necessarily reflect the views of our sponsor or Lewis & Clark Law School.
The author would like to extend her appreciation to Melissa Powers for her guidance, insight, and
editorial contributions to this report. The author also wishes to thank Nate Larsen for his editorial
contributions and Nick Lawton and Kyra Hill for their insight and support with this project. The
author also wishes to express her gratitude to Associate Dean Janice Weis and Assistant Director
Lucy Brehm of Lewis & Clark Law School’s Environmental and Natural Resources Law Program for
their input and guidance.
Finally, the author would like to thank Portland General Electric for providing images from the
utility’s 2013 Integrated Resource Plan.
The Green Energy Institute is a renewable energy policy organization within Lewis & Clark Law
School’s Environmental and Natural Resources Law Program. The Green Energy Institute
advocates for effective policies to advance renewable energy. Our mission is to facilitate a swift
transition to a sustainable, carbon-free energy grid.
For more information on the Green Energy Institute, please visit our website at
law.lclark.edu/centers/green_energy_institute.
CONTACT INFORMATION
Amelia Reiver Schlusser
Staff Attorney
[email protected]
503.768.6741
Green Energy Institute
Lewis & Clark Law School
10015 SW Terwilliger Blvd.
Portland, Oregon 97219
© 2015 Green Energy Institute. All rights reserved.
TABLE OF CONTENTS
EXECUTIVE SUMMARY ........................................................................................................................................................................ i
I. INTRODUCTION ................................................................................................................................................................................2
II. INTEGRATED RESOURCE PLANNING ........................................................................................................................................8
A. Implications of Cost-of-Service Ratemaking .........................................................................................................9
B. Emergence of Integrated Resource Planning .................................................................................................... 10
III. ADDRESSING RISK AND UNCERTAINTY IN AN EVOLVING ELECTRICITY SECTOR ................................................ 12
A. Volatility in the Power Sector .................................................................................................................................... 12
B. Adapting to Changing Conditions: Resource Planning in a Volatile Market ....................................... 15
IV. LEAST-RISK RESOURCE PLANNING ..................................................................................................................................... 17
A. An Overview of Least-Risk Resource Planning ................................................................................................. 17
B. Assessing Risk and Uncertainty ................................................................................................................................ 19
C. Resource Planning Rules and Guidelines ............................................................................................................. 20
D. Utility Implementation of Resource Planning Rules ....................................................................................... 21
V. FOSSIL FUELS VS. RENEWABLE RESOURCES: ASSESSING RISKS AND BENEFITS THROUGH LONG-TERM
PLANNING .......................................................................................................................................................................................... 27
A. The Danger of Equating Low Natural Gas Prices with Long-term Risk Mitigation ........................ 28
B. Addressing Fossil Fuel-Related Risk and Uncertainty ................................................................................... 30
C. Assessing Risks and Benefits of Renewable Resources ................................................................................ 33
VI. ESTABLISHING AN EFFECTIVE LEAST-RISK PLANNING POLICY ................................................................................. 36
A. Step 1: Revise Least-Cost Resource Requirements ........................................................................................ 37
B. Step 2: Develop Least-Risk Planning Rules ......................................................................................................... 38
1. Establish Least-Risk Planning Goals and Objectives ................................................................................. 38
2. Specify Risks, Uncertainties, and Other Factors that Utilities Must Consider ............................ 38
3. Specify the Level of Risk Analysis Required ................................................................................................... 39
4. Require Risk-Focused Resource Ranking and Resource Selection .................................................... 43
5. Transparency, Public Participation, and Regulatory Oversight ........................................................... 43
C. Step 3: Implement and Enforce Least-Risk Planning Rules ......................................................................... 45
D. Step 4: Connect IRP Approval to Ratemaking ................................................................................................... 48
CONCLUSION ..................................................................................................................................................................................... 50
A SAFE BET: LEAST-RISK RESOURCE PLANNING
EXECUTIVE SUMMARY
Fossil fuel-fired generating resources are
currently risky investments, yet investorowned utilities overwhelmingly invest capital
in fossil fuel resources rather than less-risky
renewable energy resources. States
inadvertently incentivize these investments
through resource planning rules that focus on
reducing upfront costs rather than mitigating
long-term risks. Many utilities conduct some
form of long-term resource planning in which
they forecast future energy and capacity
needs and evaluate different resource options
that are capable of meeting these needs.
Under traditional resource planning, utilities
must select the “least-cost” portfolio of
available resources to satisfy their
procurement needs. This practice likely
discourages significant investments in
renewable resources, which generally have
higher initial costs than conventional
generating facilities. “Least-risk” resource
planning is an alternative approach that may
promote renewable energy by encouraging
utilities to invest in resources with predictable
long-term operating expenses and minimal
vulnerability to risk and uncertainty.
The impetus for least-risk planning arises
from incentives created by the electricity
ratemaking process. The traditional cost-ofservice ratemaking formula creates incentives
for utilities to construct large, capitalintensive generating facilities, which earn a
profit for investors. However, because
consumers are forced to pay for these
investments over the course of many years,
these facilities can expose ratepayers to
significant risk if the plants fail to perform as
expected or incur additional unanticipated
costs over time.
Many states have promulgated integrated
resource planning rules to deter unnecessary
investment and protect ratepayers from
unanticipated costs. These rules direct utilities
to create integrated resource plans, or IRPs, in
which the utilities must project their long-term
energy and capacity needs and identify
resource mixes capable of satisfying these
needs over a ten- to twenty-year period. State
resource planning rules typically require
utilities to identify the least-cost portfolio of
available resources capable of satisfying
projected demand.
During the IRP process, utility planners
typically conduct scenario or sensitivity
analyses to determine how uncertain
variables, such as fuel price volatility or
stringent environmental compliance
obligations, could impact a portfolio’s costs
over the planning horizon. This process forces
each utility to make assumptions or
predictions about what future conditions will
be or what outcomes are most likely to occur.
Because levelized cost calculations necessarily
include projections of uncertain future costs,
such as fuel costs or environmental
compliance costs, levelized cost projections
should in theory account for risk and
uncertainty. However, a portfolio can have low
levelized costs under some future scenarios,
but very high costs under others, and the
utility has discretion to decide which scenarios
are most probable. As a result of this
discretion, under least-cost planning policies,
levelized cost calculations may fail to account
for foreseeable, high-risk outcomes that a
utility deems unlikely to occur. Consequently,
a preferred least-cost portfolio may be
i
A SAFE BET: LEAST-RISK RESOURCE PLANNING
significantly less resilient to changing
circumstances than other resource mixes.
Least-cost planning policies may
inadvertently incentivize risky resource
investments for a number of reasons. First,
levelized cost calculations generally reflect a
utility’s internal assumptions about future
conditions, and final cost projections typically
represent a portfolio’s costs under the future
outcomes that a utility subjectively thinks are
most likely to occur. Second, least-cost
planning policies rarely mandate that utilities
comprehensively assess potential risk and
uncertainty or justify their probability
determinations, and PUCs subsequently have
minimal oversight authority over portfolio
cost projections. Third, least-cost
requirements may prevent utilities from
including non-least-cost resources in their
rate bases, and therefore these utilities have
little incentive to calculate levelized costs that
significantly deviate from business-as-usual
conditions.
The way in which utilities balance cost and
risk through resource planning, moreover, has
substantial implications for renewable
resources, which many planners view as low-
risk, yet high-cost, generating resources.
Renewable resources have the capacity to
mitigate risks associated with fuel price
volatility or future environmental regulations.
When utilities and regulators place greater
value on a portfolio’s risk mitigation potential
than projected cost, preferred resource
portfolios should include a greater proportion
of renewable generating capacity. However,
cost continues to be the deciding factor in a
majority of resource planning decisions, and
renewable resources have struggled to
compete with historically low natural gas
prices.
Least-cost planning policies may
inadvertently incentivize risky resource
investments for a number of reasons. First,
levelized cost calculations generally reflect a
utility’s internal assumptions about future
conditions, and final cost projections typically
represent a portfolio’s costs under the future
outcomes that a utility subjectively thinks are
most likely to occur. Second, least-cost
planning policies rarely mandate that utilities
comprehensively assess potential risk and
uncertainty or justify their probability
determinations, and PUCs subsequently have
minimal oversight authority over portfolio
ii
A SAFE BET: LEAST-RISK RESOURCE PLANNING
cost projections. Third, least-cost
requirements may prevent utilities from
including non-least-cost resources in their
rate bases, and therefore these utilities have
little incentive to calculate levelized costs that
significantly deviate from business-as-usual
conditions.
Least-risk resource planning presents an
alternative planning policy that aims to reduce
ratepayer exposure to risk and uncertainty.
Least-risk resource planning directs utilities
and regulators to quantify the risks and
uncertainties associated with all resource
options. It then requires utilities to select the
resource portfolio that most effectively
reduces exposure to plausible or
unreasonable risks under all potential
outcomes. Least-risk planning is an emerging
concept in the context of integrated resource
planning, and while some states have revised
their IRP requirements to incorporate leastrisk provisions, there are currently no uniform
standards to define this planning approach.
Least-risk planning policies have the
potential to help mitigate the risks created by
least-cost planning. First, an effective leastrisk planning policy will require each utility to
comprehensively assess portfolio vulnerability
to all foreseeable risks and evaluate the
probabilities of uncertain outcomes. Second,
least-risk planning policies will direct each
utility to justify the assumptions it made when
predicting uncertain future conditions and
explain the conclusions it reached regarding
the probabilities of potential outcomes. Third,
least-risk planning policies will allow for public
participation and regulatory oversight over
the planning process. PUCs will also have the
authority to enforce least-risk planning
requirements when making IRP approval
decisions. Finally, least-risk planning policies
will provide each utility with some assurance
that investments in least-risk resources will be
eligible for cost recovery.
There are a number of general steps that
regulators can follow to develop and
implement effective least-risk planning
regimes. First, regulators must review and
revise existing resource planning regulations
to replace least-cost resource requirements
with least-risk mandates. Second, regulators
must develop least-risk planning rules
establishing threshold risk assessment
parameters. Third, regulators must ensure
that utilities effectively implement least-risk
planning requirements. Finally, regulators
must connect resource plan approval to the
ratemaking process to provide a level of
assurance that utility investments in least-risk
resources may be eligible for cost recovery
(and that ratepayers are not on the hook for
higher risk investments).
Utilities that adequately seek to minimize
exposure to risk and uncertainty will be better
able to adapt to the energy realities of the 21st
century. However, utilities are unlikely to alter
their existing resource planning practices on
their own accord. Least-risk planning will be
necessary to facilitate the transition away
from the current high-risk, fossil fueldependent electricity system, and it is up to
state regulators to establish least-risk
resource planning policies that prioritize risk
mitigation over short-term cost reduction.
When effectively implemented and enforced,
these policies should mitigate risks to
ratepayers and investors and advance
renewable energy development by equalizing
the playing field between renewables and
fossil fuels.
iii
A SAFE BET: LEAST-RISK RESOURCE PLANNING
I. I NTRODUCTION
Before electric utilities invest in new
generating resources, most states require
them to engage in some form of long-term
resource planning that forecasts future load
and capacity needs and evaluates various
resource options capable of meeting these
needs. These planning requirements help
protect electricity consumers from unduly
high electricity rates by preventing utilities
from investing in unnecessary energy
resources. Resource planning requirements
are therefore valuable state policies that help
inform energy development over the course of
many years. One shortfall of these policies,
however, is that utilities are traditionally
required to select the least-cost portfolio of
resources identified through the resource
planning process to satisfy their future energy
and capacity needs.1 This requirement may
lead utilities to overlook significant risks and
uncertainties that can impact a resource’s cost
or performance over its lifetime. Moreover,
prioritizing cost reduction over risk mitigation
may deter investments in renewable
resources and energy storage, which are
generally low-risk, yet potentially high-cost
resources.2 Least-risk resource planning
presents an alternative policy option that
prioritizes risk mitigation and long-term cost
stabilization over short-term cost reductions.
This planning approach encourages utility
investments in resources with predictable
long-term costs, such as renewable energy
and energy storage resources. By replacing
least-cost planning policies with least-risk
planning policies, states can reduce ratepayer
vulnerability, eliminate a barrier to renewable
energy development, and facilitate the
transition to a more resilient, sustainable
energy system.
2
A SAFE BET: LEAST-RISK RESOURCE PLANNING
The traditional cost-of-service
ratemaking formula typically dictates how
utilities may allocate a resource’s costs among
ratepayers. This ratemaking formula enables a
utility to recover its operating expenses and
the value of any authorized capital
investments through consumer electricity
rates.3 Utilities are entitled to earn an
additional rate of return (i.e. a profit) on capital
expenditures, but not on operating expenses.4
The ratemaking formula thus encourages
utilities to build power plants and electricity
infrastructure, because utilities will only earn a
direct rate of return on those types of
investments. Of course, this profit incentive
may also encourage utilities to overbuild.
Least-cost planning aims to curtail this
dynamic by requiring utilities to create
Integrated Resource Plans (IRPs or resource
plans) identifying the resource portfolios
capable of satisfying long-term energy and
capacity needs at the lowest costs.5
Integrated resource planning also attempts
to protect ratepayers from unanticipated cost
increases in the future. Electricity rates are set
prospectively by state Public Utility
Commissions (PUCs), which means that
utilities must project their anticipated future
operating expenses.6 However, energy price
forecasting is notoriously difficult, and history
is full of examples of unexpected fuel price
increases. Although the prospective
ratemaking rule might suggest that utilities
RATEMAKING FORMULA
R = (B x r) + O
R: revenue requirement
B: rate base
r: rate of return
O: operating expenses
Cost-of-service ratemaking enables utilities to earn a profit
on capital investments, which encourages construction of
large power plants.
are responsible for operating cost increases
that occur between ratemaking proceedings,
cost increases resulting from rising fuel prices
are often passed onto ratepayers through fuel
adjustment clauses.7 Fuel adjustment clauses
enable utilities to quickly adjust their
electricity rates between ratemaking
proceedings in response to unanticipated fuel
price fluctuations.8 Utilities are not entitled to
profit off of fuel-based rate adjustments,9 but
the availability of these clauses reduces the
incentive for utilities to accurately project
future fuel costs. Ratepayers are therefore
vulnerable to risks presented by future fuel
cost increases.
A resource’s costs may also rise in
response to future environmental regulations,
such as greenhouse gas emissions limitations.
If regulations require installation of additional
emission controls, expenses associated with
regulatory compliance will likely constitute
capital expenditures that are recoverable
through the utility’s rate base. If these
regulations instead require operational
changes, these operating cost increases will be
passed on to consumers through a subsequent
ratemaking proceeding. Utilities therefore
have little incentive to invest in resources with
stable, predictable operating costs.
3
A SAFE BET: LEAST-RISK RESOURCE PLANNING
In fact, the ratemaking formula may
perversely encourage utilities to invest in
resources that may require future upgrades to
comply with future regulatory requirements,
because utilities will earn a profit on facility
retrofits. Least-cost regulatory requirements
may exacerbate, rather than mitigate, this
dynamic in an uncertain regulatory setting.
This is because utilities are typically
encouraged or required to invest in least-cost
resources. If a utility cannot show that
regulatory changes are likely to occur, leastcost planning will incentivize the utility to
invest in the lower-cost resource and modify
the resource as necessary to comply with
future regulations. Ratepayers thus bear the
risk that the costs associated with utility
resource investments may rise over time.
Where fossil fuel-dependent generating
resources are involved, the risk of future cost
increases is significant.
This does not mean that utilities or their
investors are entirely unaccountable for risky
resource investments. State PUCs have broad
authority to determine whether utilities are
entitled to a rate of return on their capital
investments.10 PUC decisions involving coal
plant investments indicate that regulators may
be increasingly inclined to prohibit utilities
from passing on certain future costs to
consumers.11 For example, in 2008, the Texas
PUC limited the Southwestern Electric Power
Company’s ability to pass some future carbon
mitigation costs onto consumers.12 Under the
PUC’s decision, any carbon costs exceeding
$28 per ton must be born by the utility, rather
than ratepayers.13 Utilities and their investors
may therefore also be vulnerable to risks
presented by unanticipated cost increases, at
least insofar as future carbon costs are
concerned.
In the future, PUCs may prohibit
utilities from passing high carbon costs
onto ratepayers.
Despite this vulnerability, least-cost
planning requirements may discourage
utilities from adequately evaluating resource
portfolio exposure to risks and uncertainties,
and may encourage utilities to invest in
capital-intensive resources that are
disproportionately vulnerable to cost
increases. The integrated resource planning
process traditionally mandates that a utility
identify the least-cost resource mix to satisfy
future energy and capacity needs. In this
context, the least-cost resource mix generally
refers to the combination of resources with
the lowest levelized cost.14 Levelized cost
represents the total cost of building and
operating a generating resource over its
projected lifespan, averaged over a perkilowatt-hour or megawatt-hour basis.15 This
cost estimate aims to encompass all
anticipated costs, including capital
expenditures, operations and maintenance
costs, fuel costs, taxes, and environmental
compliance costs.16 Utility IRPs typically
define levelized costs as the present value of
revenue requirement, or PVRR, which also
includes resource depreciation and return on
investment.17
4
A SAFE BET: LEAST-RISK RESOURCE PLANNING
Because levelized cost calculations include
all projected costs associated with the
resource over the entirety of the planning
period, utility planners must attempt to
predict a number of uncertain costs, including
those associated with environmental
regulations and fuel prices.18 In theory, a leastcost resource should also be a low-risk
resource, because a resource with the lowest
levelized cost should have the lowest potential
for cost increases over the planning horizon.
However, a portfolio may be least-cost under
some scenarios, yet very high-cost under
others, and the utility ultimately must decide
which future scenarios are most probable.
Under least-cost planning policies,
levelized cost calculations may be inaccurate
for a number of reasons. First, resource cost
projections reflect underlying utility
assumptions regarding future conditions or
the probability that certain outcomes will
occur, and utility biases may influence these
assumptions and probability determinations.
Second, least-cost planning policies typically
fail to require utilities to comprehensively
assess risk and uncertainty or justify their
probability determinations. PUCs therefore
exercise minimal oversight or enforcement
SHORTFALLS of LEAST-COST
PLANNING
•
utility assumptions and biases may
influence resource cost projections
•
no mandate to comprehensively assess
risk or justify probability
determinations
•
minimal or no PUC oversight over cost
projections
•
may limit cost recovery for non-least
cost resources and discourage
investments in renewable resources
Least-cost planning incentivizes investments in
natural gas-fired generating facilities, which
have uncertain long-term operating costs.
authority over levelized cost projections.
Finally, least-cost requirements may prohibit
utilities from including non-least-cost
resources in their rate bases, which may
encourage utilities to create very conservative
cost projections reflecting business-as-usual
policy assumptions. For example, a utility in a
least-cost jurisdiction benefits from assuming
that fuel and environmental compliance costs
will remain low, because these assumptions
increase the potential for the utility to build
(and earn a rate of return on) large capital
investments. If these assumptions are
inaccurate, the utility can pass future
operating cost increases on to consumers.
As a result of these dynamics, traditional
least-cost resource planning policies likely
discourage significant investment in
renewable resources and energy storage,
which currently tend to have higher capital
costs than conventional generating resources.
PUCs in states with strict least-cost
requirements may determine that
investments in renewable resources are
imprudent and thus deny a utility from
recovering these capital costs through
electricity rates.
5
A SAFE BET: LEAST-RISK RESOURCE PLANNING
“Least-risk” resource planning provides a
policy alternative that may encourage utility
investment in renewable energy. Least-risk
planning aims to minimize vulnerability to risk
and uncertainty by requiring utilities to select
resource portfolios with the least exposure to
potential risks over the planning period. This
planning method requires utilities to evaluate
the foreseeable risks and benefits associated
with various energy resources and identify the
resource portfolios that are least vulnerable to
risk and uncertainty during the planning
period. In this context, “risk” primarily refers
to the threat of future cost increases or
operating restrictions. In addition, least-risk
planning policies can encourage utilities to
account for certain externalities associated
with specific generating resources, such as
negative environmental impacts.
Least-risk resource planning alleviates a
number of the concerns associated with leastcost planning. First, an effective least-risk
planning policy will require each utility to
comprehensively assess portfolio vulnerability
to all foreseeable risks and evaluate the
probabilities of uncertain outcomes. Second,
least-risk planning policies will direct each
utility to justify the assumptions it made when
predicting uncertain future conditions and
LEAST-RISK PLANNING
SAFEGUARDS
•
require comprehensive assessment of
all foreseeable risks and uncertainties
•
utilities must justify assumptions and
explain probability determinations
•
requires public participation and
regulatory oversight and enforcement
•
clarifies that least-risk resource
investments may be eligible for cost
recovery
Least-risk planning policies should promote renewable
energy development by encouraging investment in
resources with minimal environmental externalities
and predictable operating expenses.
explain the conclusions it reached regarding
the probabilities of potential outcomes. Third,
least-risk planning policies will allow for public
participation and regulatory oversight over
the planning process, and PUCs will have the
authority to enforce least-risk planning
requirements when making IRP approval
decisions. Finally, least-risk planning policies
will provide each utility with some assurance
that investments in least-risk resources will be
eligible for cost recovery. When effectively
implemented, these policies should mitigate
risks to ratepayers and investors, and may also
advance renewable energy development by
equalizing the playing field between
renewables and fossil fuels.
Least-risk planning policies should promote
renewable energy development by
encouraging investment in resources with
minimal environmental externalities and
predictable operating expenses. Renewable
resources are an attractive addition to a
diversified resource portfolio due to their
ability to mitigate risks associated with fuel
price volatility or environmental compliance
obligations. Likewise, increased energy
storage capacity will increase reliability and
further hedge against future fossil fuel price
6
A SAFE BET: LEAST-RISK RESOURCE PLANNING
increases. When regulators prioritize longterm risk mitigation over short-term cost
reduction, preferred portfolios should include
more renewable energy and storage capacity
than traditional least-cost portfolios. Leastrisk planning policies aim to prevent cost
projections from superseding risk
considerations, and they may be necessary to
ensure that utilities assess the long-term
benefits of renewables in addition to capital
costs.
The U.S. electricity sector is entering into
an era of dramatic change as states transition
to a cleaner, more resilient energy system.
Utilities that engage in strategic, risk-focused
resource planning will be better able to adapt
to the shifting energy needs and goals of the
21st Century. However, vertically integrated
investor-owned utilities are regulated
monopolies, and thus are not subject to the
competition that generally drives industrial
innovation.19 Regulated utilities are therefore
unlikely to implement innovative, least-risk
planning practices on their own accord.
Instead, policymakers must adopt resource
planning policies that require utilities to
prioritize risk mitigation. These policy
frameworks must be sufficiently flexible to
enable utility planners to respond to shifting
legal and regulatory conditions.
This paper 1) explains how least-risk
planning can help promote renewable energy,
2) examines how a few states have employed
risk-focused resource planning in practice, and
3) builds off of these examples to recommend
improvements to resource planning rules and
practices. Least-risk planning is an emerging
alternative to least-cost resource planning,
and no state has yet established a pure leastrisk planning regime. This paper provides
examples from existing planning regulations
and utility resource plans to illustrate the
least-risk planning concept.
Part II of this report introduces the concept
of integrated resource planning and provides a
general overview of utility resource planning.
Part III describes emerging risks and
uncertainties that have the potential to impact
our evolving energy sector. Part IV explains
the concept of least-risk planning and provides
examples of how risk-focused planning
requirements may be applied in practice. Part
V explores the implications least-risk planning
may have on renewable energy development.
Finally, Part VI provides an overview of the
steps regulators can take to develop and
implement effective least-risk planning
regimes. This report concludes that least-risk
planning policies should be developed and
implemented throughout the country to
reduce investor and ratepayer vulnerability to
risk and incentivize renewable energy
development.
Pumped hydroelectric facilities function as giant
batteries. The Tennessee Valley Authority’s 1,652
MW Raccoon Mountain Pumped Storage Plant,
shown here, pumps water from a lower reservoir
during periods of low demand and releases it
through four hydroelectric generators during
periods of high demand. High-capacity energy
storage facilities can help balance variable
renewable energy and mitigate ratepayer risk.
7
A SAFE BET: LEAST-RISK RESOURCE PLANNING
II. I NTEGRATED R ESOURCE P LANNING
Many utilities engage in integrated
resource planning to identify the resources
they will need to satisfy electricity demand in
the future. Integrated resource planning is a
process in which utilities evaluate a range of
potential resource options that can satisfy
projected future energy and capacity
requirements. The federal Energy Policy Act
of 1992 defined “integrated resource
planning” as “a planning and selection process
for new energy resources that evaluates the
full range of alternatives . . . in order to provide
adequate and reliable service to its electric
customers at the lowest system cost.”20 The
ultimate objective is to identify electric
generating resources that will reliably meet
consumer demand and comply with regulatory
requirements over an extended period of time,
typically ranging from ten to twenty years.21
The integrated resource planning process
traditionally requires utilities to identify the
least-cost resource mix that will satisfy future
load and reliability needs.22 In this context,
least-cost resource mix generally refers to the
combination of resources with the lowest
levelized cost over the full planning horizon.23
A resource’s “levelized cost” is the
expected cost of electricity averaged on a per
megawatt-hour basis over the life of the
generating resource. This cost estimate aims
to encompass all projected costs associated
with the resource, including capital
expenditures, operations and maintenance
costs, fuel costs, and environmental
compliance costs.24 Levelized cost estimations
thus require an evaluation of potential risks
and uncertainties that may cause costs to
increase in the future.
STATES WITH INTEGRATED RESOURCE PLANNING OR SIMILAR PROCESSES
8
A SAFE BET: LEAST-RISK RESOURCE PLANNING
One of the objectives of integrated
resource planning is to prevent imprudent
resource investments. The traditional cost-ofservice ratemaking model creates incentives
for utilities to make large capital investments
in generating resources and infrastructure. By
requiring utilities to project long-term
resource needs and costs, integrated resource
planning aims to prevent long-term
investments in unnecessary or unduly
expensive resources. This Part explains how
the traditional ratemaking formula
incentivizes utilities to invest in capitalintensive resources, and explores how
integrated resource planning aims to
safeguard ratepayers from unnecessary costs.
A. IMPLICATIONS OF COST-OF-SERVICE RATEMAKING
The impetus for least-risk resource
planning stems from the traditional utility
ratemaking model and the underlying
investment incentives this model creates.
Vertically integrated investor-owned electric
utilities typically earn revenue through costof-service electricity rates established by state
public utility commissions, or PUCs.25 These
rates must be just and reasonable for utilities
and electricity customers, and they are
designed to enable utilities to recover their
operating expenses and earn reasonable rates
of return on capital investments.26 Under the
traditional cost-of-service ratemaking
formula, utilities are entitled to earn rates of
return on their rate bases, which include all
capital investments the utilities made in
providing electricity service.27 Capital
investments include the costs of building and
maintaining generating facilities and other
infrastructure used to create and transmit
electricity to end users.28 Utilities are also
entitled to recover all reasonable operating
expenses, which include all non-capital costs
necessary to deliver electricity to consumers,
including fuel costs.29 Under the traditional
formula, operating costs do not earn a rate of
return.30
Historically, this cost-of-service
ratemaking formula has incentivized utilities
to invest in large, capital-intensive generating
resources, such as fossil fuel-fired power
plants, which earn a rate of return for
investors.31 The costs of these facilities could
be included in electricity rates for multiple
decades, and if a facility is removed from
service prematurely, ratepayers could
potentially be forced to pay for a facility that
no longer provides power.32 To protect
ratepayers from potentially exploitative rates
resulting from unnecessary capital
investments, PUCs developed a series of
mitigating doctrines to ensure that only
reasonable investments get included in a
utility’s rate base. Under the prudent
investment doctrine, a utility is only entitled
to recover “prudent” capital investments.33
Under the used and useful doctrine, a utility is
not permitted to include a prudent capital
investment in its rate base unless the facility is
both necessary and placed into
service.34Finally, electricity rates are
established prospectively, so a utility is
required to project its future operating
expenses at the time of the ratemaking
proceeding.35 Therefore, if operating costs
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A SAFE BET: LEAST-RISK RESOURCE PLANNING
rise above a utility’s projections, the utility
may lose revenue.
While the prudent investment and used
and useful doctrines were designed to protect
ratepayers from exploitative rates, they
expose utilities to significant risk in the event
that a facility never enters into service. This is
precisely what happened during the nuclear
power boom of the 1970s, when rising
construction costs, inaccurate demand
projections, and the 3 Mile Island incident led
utilities to cancel construction on or abandon
dozens of nuclear plants before the facilities
entered into service.36 Though these plants
were not used and useful, most PUCs allowed
the utilities to recover at least some of their
costs from ratepayers. While the utilities
often did not earn a rate of return on the failed
investments, ratepayers nonetheless were
forced to pay for the utilities’ failures.37 Some
states, however, prohibited the utilities from
recovering their investments entirely, at great
expense to the utilities and their investors.38
The controversy surrounding these stranded
nuclear plant costs revealed the limitations of
the prudent investment and used and useful
doctrines in preventing risky capital
investments in large, expensive generating
facilities.
A nuclear power plant can cost billions of dollars.
B. EMERGENCE OF INTEGRATED RESOURCE PLANNING
Integrated resource planning emerged in
the 1980s in response to the nuclear cost
overruns and fuel shortages of the late
1970s.39 These planning rules were primarily
designed to function within the electricity
sector of the 1980s, in which large-scale, fossil
fuel-fired power plants were the dominant
generating resources available.40 Regulators
wanted to protect ratepayers from
unanticipated rate increases and directed
utilities to identify resource portfolios that
would satisfy increases in energy demand at
the lowest cost to consumers.41 As of 2011,
27 states had adopted integrated resource
planning rules directing utilities to project
their future energy and capacity needs and
identify portfolios of low-cost resources
capable of satisfying consumer energy
demands over an extended time frame.42
In the resource planning context, all
anticipated and foreseeable costs associated
with a resource are levelized over the planning
horizon. These costs typically include initial
capital expenditures and operating and
maintenance costs, fuel costs, and
environmental compliance costs.43 While
some costs, such as capital expenditures and
operating and maintenance costs, may be
relatively easy to estimate, costs tied to fuel
prices or environmental regulatory
requirements are more uncertain over
extended timeframes. Utility planners must
nonetheless attempt to predict what future
costs may be imposed on specific generating
resources under a variety of potential
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A SAFE BET: LEAST-RISK RESOURCE PLANNING
LEVELIZED COST RANGES (in U.S. dollars per megawatt hour)
Data from Lazard’s Levelized Cost of Energy Analysis v. 8.0 (2014)
scenarios. Accordingly, during the integrated
resource planning process, utilities typically
conduct scenario or stochastic analyses44 to
evaluate risks and uncertainties associated
with, for example, natural gas prices,
wholesale electricity rates, and environmental
regulations.45 However, the risks considered
and evaluative methods used vary among
utilities, and final cost calculations may differ
dramatically.46
Utilities should aim to estimate costs as
accurately as possible during the integrated
resource planning process, because integrated
resource plans (IRPs) heavily influence a
utility’s ability to recover the value of its
investments through electricity rates. As
section A explained, PUCs generally allow
utilities to recover capital costs for “prudent”
investments in resources that are “used and
useful.”47 In many states, IRPs inform PUC
decisions on whether a utility’s investment in a
new generating facility was necessary or
“prudent.”48 While IRPs are rarely binding on
utilities, PUCs generally determine that
The levelized costs of renewable
energy resources have decreased
dramatically over the past decade.
In 2014, the levelized cost of
distributed solar generation ranged
from $138 to $203 per megawatthour when federal tax credits were
accounted for. The levelized cost
of wind power ranged from $37 to
$81 per megawatt-hour without
federal incentives, and dropped as
low as $14 per megawatt-hour
with federal tax credits. In
comparison, when fuel price
fluctuation was taken into
account, the levelized cost of
natural gas combined cycle
technology ranged from $52 to
$96.
resource investments are necessary and
prudent if the investments are consistent with
PUC-approved or “acknowledged” IRPs.49
This process provides PUCs with a degree
of oversight over integrated resource planning
that may influence the manner in which a
utility addresses risk and uncertainties. A riskaverse PUC, for example, may refuse to
acknowledge an IRP that fails to adequately
account for potential fuel price volatility or
foreseeable carbon regulations. On the other
hand, a PUC may require strict compliance
with least-cost planning mandates and may
refuse to acknowledge an IRP where the
preferred resource mix is not least-cost, even
if the least-cost alternative exhibits more
vulnerability to risk. Because a failure to
obtain PUC acknowledgment of an IRP
indicates that the PUC may later refuse to
approve investments in resources identified in
the IRP, utilities are heavily incentivized to
comply with PUC directives regarding utility
planning practices.
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A SAFE BET: LEAST-RISK RESOURCE PLANNING
III. A DDRESSING R ISK AND U NCERTAINTY
AN E VOLVING E LECTRICITY S ECTOR
Although utility planning has arguably
improved since the emergence of integrated
resource planning, it has not prevented
significant investments in potentially risky
resources. The U.S. electricity sector is
currently adjusting to a series of disruptive
conditions and developments, and
uncertainties regarding future fuel prices and
climate change regulations are creating
significant challenges for utility resource
planning. The entrenched least-cost resource
IN
planning model appears ill-suited for today’s
evolving electricity sector and may prevent
utilities from adequately mitigating exposure
to emerging risks.
This section describes some of the
emerging risks and sources of uncertainty that
may impact the evolving 21st century energy
sector, and discusses how utility resource
planning practices are responding—or failing
to respond—to changing market and
regulatory conditions.
A. VOLATILITY IN THE POWER SECTOR
The American electricity sector is currently
undergoing a period of substantial change,
which, according to a recent Ceres report, has
created “a level and complexity of risks that is
perhaps unprecedented in the industry’s
history.”50 Climate change may present the
most significant source of uncertainty for
electric utilities. It is extremely likely, if not
inevitable, that greenhouse gas emissions
from existing power plants will be subject to
some form of regulation over the coming
decade. Indeed, many states and regions
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A SAFE BET: LEAST-RISK RESOURCE PLANNING
already regulate greenhouse gas emissions
from electric power plants,51 and greenhouse
gas emissions from both new and existing
sources will likely be regulated under section
111 of the Clean Air Act in the near future.52
Fossil fuel resources may therefore be
disproportionately vulnerable to cost
increases stemming from future regulatory
actions, and utilities with carbon-intensive
generation resources expose their investors
and ratepayers to significant levels of risk.
The electricity sector is responsible for
approximately 40% of the nation’s carbon
dioxide emissions.53 According to a California
survey of utility IRPs, most regulated utilities
now assess risks associated with potential
carbon costs during the IRP process.54 Most
utilities surveyed conducted some form of
scenario analysis in which they imposed a
range of hypothetical carbon costs on
potential resource portfolios.55 However, the
California survey was unable to determine
whether these utilities considered the
potential carbon costs associated with their
existing generation assets, or whether these
scenario analyses only evaluated prospective
generation options.56 Perhaps more
importantly, these carbon risk analyses did not
appear to influence every utility’s final
portfolio selection, and cost continued to have
the strongest influence on the majority of
portfolio selections.57
While utilities and regulators increasingly
acknowledge the risks associated with coalfired electricity, they have not acknowledged
the risks associated with replacing coal with
another fossil fuel, natural gas. Over the last
ten years, more than 120 proposals to
construct new coal-fired power plants have
been canceled due to environmental and cost
concerns.58 EPA’s proposed New Source
Performance Standards for greenhouse gas
emissions from new electricity generating
units effectively prohibit the construction of
new coal plants without carbon capture and
sequestration.59 Due to increased regulation
of coal-fired power and recent decreases in
natural gas prices, utilities have looked to
natural gas to fuel future energy demands.
However, this increased reliance on natural
gas may actually increase utilities' risk
exposure.
Natural gas combined cycle facilities typically
emit between 800 and 1,000 pounds of carbon
dioxide per megawatt hour.
Historically, natural gas prices were very
volatile, but the recent explosion of hydraulic
fracturing (fracking) has contributed to
historically low fuel prices.60 Utilities appear to
assume that natural gas prices will remain low
for the foreseeable future,61 yet this
assumption may be shortsighted. For example,
researchers at Credit Suisse and the
University of Pittsburgh found that it costs
significantly more to extract gas through
fracking than through traditional drilling.62
According to this data, the average cost to
produce natural gas from a new well using
hydraulic fracturing is around $9–$10 per
MMBtu (million British Thermal Units).63
However, natural gas currently sells for
around $4 per MMBtu.64 It appears, then, that
current natural gas prices may be artificially,
and temporarily, low. Increases in regulatory
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A SAFE BET: LEAST-RISK RESOURCE PLANNING
To prevent global
temperatures from
increasing more than
two degrees Celsius,
sixty to eighty percent
of current fossil fuel
reserves must remain
in the ground.
oversight over natural gas extraction activities
or the emergence of a robust natural gas
export market could cause prices to rise
dramatically.65 Moreover, natural gas-fired
generation stations produce greenhouse gas
emissions,66 and thus are not immune to the
carbon regulatory risks discussed above. Even
without regulatory changes, some economists
believe the natural gas sector’s economic
viability is overstated and that natural gas
prices will have to rise—perhaps
substantially—in the foreseeable future.67
Many utilities, however, fail to seriously
address natural gas fuel price uncertainties in
their resource planning processes. California’s
2008 IRP survey found that all utilities
conducted fuel price forecasting, yet very few
of the IRPs assessed market price uncertainty
through scenario analysis.68 Of the utilities
that did engage in this analysis, most merely
adjusted fuel prices up or down by a set
percentage.69
The electricity sector’s generally slow and
inconsistent response to addressing the risks
and uncertainties associated with carbon
emissions is raising concerns in the
investment community.70 Preventing global
temperatures from rising more than 2ºC will
require substantial reductions in fossil fuel
consumption through 2050.71 According to
the Carbon Tracker Initiative, this means that
60–80% of current identified coal, oil, and gas
reserves must never be combusted, yet the
top 200 fossil fuel companies have allocated
an estimated $674 billion for locating and
extracting additional reserves.72 If stringent
carbon emissions limitations are implemented,
these companies will be left with significant
stranded assets. In a recent Ceres report,
Navigant Consulting noted that utilities with
carbon-intensive resource portfolios could
experience revenue reductions up to 20%.73
These losses would be passed on to
consumers or utility shareholders, and could
cause the credit ratings of investor-owned
utilities to drop.74 The average credit rating
for the electric utility industry has already
dropped from an A to a BBB, signifying a
heightened investment risk that, in turn,
increases utility financing costs.75 Moreover,
in the event that stringent emissions
restrictions are implemented, inefficient coalfired power plants may become uneconomical
to operate, and utilities may opt to retire these
facilities rather than invest in expensive
emissions controls. These premature
retirements could further compound existing
financial risks.76
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A SAFE BET: LEAST-RISK RESOURCE PLANNING
B. ADAPTING TO CHANGING CONDITIONS: RESOURCE PLANNING IN A
VOLATILE MARKET
In 2012, the National Association of
Regulatory Utility Commissioners hosted a
workshop called the Energy Risk Lab, which is
an interactive simulation game designed to
assess utility and regulatory responses to realworld energy policy shifts.77 The game
required participants to respond to a number
of regulatory scenarios, including potential
carbon pricing, gas price volatility, a national
Clean Energy Standard, fracking moratoria,
and new emissions regulations under the
Clean Air Act.78 Participants were required to
develop and manage resource portfolios that
could comply with environmental regulations,
maintain reliability, and control costs under
changing regulatory conditions.79 At the end
of the workshop, participants that strategically
planned ahead for future risks and developed
diverse portfolios of low-risk resources
achieved the most successful long-term
outcomes.80 Participants that failed to
implement a comprehensive strategy to
respond to future risks, and instead only
reacted to one variable at a time, “suffered
rapidly increasing costs, an inability to
maintain reliability, and delays in complying
with regulations.”81 According to Miles Keogh,
the game’s organizer, the exercise provided
important insights into resource planning:
first, a strategic approach to risk mitigation
yields more favorable results than a reactive
approach, and second, portfolios with diverse
resources outperformed lower-cost portfolios
with only a single resource type.82
Warren Gretz, NREL (1991)
Public Service Company of Colorado’s Cherokee Station is a coal-fired power plant located near
downtown Denver. The utility aims to retire the plant’s four coal-fired units by 2017, sixty years after
the facility entered into service in 1957.
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A SAFE BET: LEAST-RISK RESOURCE PLANNING
Utilities have an opportunity to mitigate
many of the foreseeable risks discussed above
by engaging in comprehensive, risk-focused
resource planning. However, while some
utilities acknowledge risks presented by fossil
fuel investments and consider the riskreduction benefits of renewable resources,83
cost continues to be the deciding factor in a
majority of resource planning decisions.84 As a
result, renewable resources have struggled to
compete with historically low natural gas
prices, and utilities continue to make high-risk
investments in fossil fuel resources.85
Through the integrated resource planning
process, regulators traditionally require
utilities to identify the least-cost resource
portfolio that will satisfy projected demand
over the course of the planning horizon.
Existing least-cost planning structures allow
utilities to make assumptions regarding the
costs and risks associated with renewable and
fossil fuel resources, and many utilities impose
constraints on renewables within their
analyses that may manipulate modeling
results.86 In many instances, IRPs may reflect
utilities’ resource preferences and biases, and
thus may apply unrealistic assumptions
regarding future costs.87 Least-cost planning
analyses may not adequately address
potential cost increases resulting from policy
reforms, and current resource planning
practices may thus expose utilities, investors,
and ratepayers to unacceptable levels of
risk.88
The outcomes from the Energy Risk Lab
demonstrate how important strategic, riskbased resource planning is in an evolving
regulatory environment. To remain profitable,
utilities must adequately address risks and
opportunities associated with future
greenhouse gas emissions limitations, fuel
availability and price volatility, environmental
regulations, and federal and state energy
policies. These risks and opportunities affect
all stakeholders. Moreover, investors,
ratepayers, and regulators cannot avoid risk
simply by following the status quo. The Brattle
Group estimates that the total capital invested
in the U.S. electricity system will double by
2030.89 Generating resources built today may
still be operational forty years from now, and
regulators must ensure that utilities invest
capital wisely. Regulators can best minimize
risks to ratepayers by requiring utilities to
engage in careful, comprehensive resource
planning that emphasizes risk reduction over
least-cost requirements. Part IV discusses
resource planning policies that aim to reduce
vulnerability to foreseeable risks and
uncertain outcomes.
To remain profitable in the 21st
Century electricity sector, utilities
must minimize their exposure to a
variety of risks and uncertainties
associated with fuel price volatility
and greenhouse gas emissions
regulation. Renewable energy
resources like wind and solar power
help to mitigate ratepayer and investor
vulnerability to these sources of risk.
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A SAFE BET: LEAST-RISK RESOURCE PLANNING
IV. L EAST -R ISK R ESOURCE P LANNING
“Least-risk resource planning” refers to
resource planning practices designed to
minimize exposure to future risks and
uncertainties. Least-risk resource planning
directs utilities and regulators to quantify the
risks and uncertainties associated with all
resource options. Utilities then must select
the resource portfolio that most effectively
reduces exposure to foreseeable or
unreasonable risks. This planning model helps
to ensure that ratepayer and investor
concerns are accounted for by allowing
stakeholders to participate in the planning
process, and it provides state utility regulators
with enforcement authority to ensure that
utilities are adequately addressing risk and
uncertainty. This Part provides an overview of
the least-risk resource planning concept and
describes existing resource planning
requirements and practices designed to
reduce exposure to risk and uncertainty.
A. AN OVERVIEW OF LEAST-RISK RESOURCE PLANNING
Least-risk resource planning aims to
reduce vulnerability to risk and uncertainty by
evaluating a wide range of potential future
scenarios and outcomes and identifying a
resource portfolio that will best ensure longterm price stability under all potential
outcomes.90 Least-risk planning is an emerging
concept in the context of integrated resource
planning, and there are currently no uniform
standards to define this planning approach. In
this paper, the term “least-risk resource
planning” refers to an alternative resource
planning process comprised of components
borrowed from state resource planning rules
and guidelines, utility IRP practices, and policy
analyses. While no state has developed or
implemented a pure least-risk planning
regime, some states have incorporated leastrisk planning requirements into their IRP
regulations or guidelines.91 A recent Ceres
report identified a variety of benefits
stemming from such “risk-aware regulation,”
including consumer benefits from lower-risk
long-term investments, utility benefits from a
more predictable business environment,
investor benefits from reduced threats to cost
recovery, regulatory benefits from increased
transparency and improved decision-making,
and societal benefits from a “cleaner, smarter,
more resilient electricity system.”92
BENEFITS OF LEAST-RISK PLANNING
Consumers: low-risk resource
investments
Utilities: increased economic stability and
regulatory certainty
Investors: reduced risk of stranded costs
and cost recovery denials
Regulators: increased transparency and
informed decision-making
Society: more sustainable, resilient
electricity system
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A SAFE BET: LEAST-RISK RESOURCE PLANNING
To better understand the strengths and
benefits of least-risk planning, it helps to
compare this new planning approach with the
established least-cost approach. Under
traditional least-cost resource planning,
utilities aim to identify the combination of
resources that will satisfy demand and
capacity needs at the lowest cost over the
entirety of the planning horizon. Utility
planners typically conduct scenario or
sensitivity analyses to determine how specific
uncertainties, such as fuel price volatility or
increased regulatory controls, could impact a
resource portfolio’s costs over the planning
horizon.93 Utilities generally select the
resource portfolio with the lowest cost over
the majority of possible futures. However,
when there is a substantial degree of
uncertainty surrounding different possible
future scenarios, a preferred resource
portfolio may be least-cost under a number of
scenarios, yet very high-cost under other
scenarios.94
For example, many utilities now conduct
scenario analyses to measure the impacts of
potential carbon regulations.95 Under
IRP SCENA RIO EXA MPLES
•
•
•
•
•
•
•
•
•
•
high/low fuel prices
high/low carbon costs
high/low capital costs (specific
resource types)
high/low load growth
high/low wholesale electricity prices
subsidies available/not available
high/low precipitation
solar PV penetration
high/low consumer energy efficiency
high/low RPS mandates
scenarios that assume no carbon costs will be
imposed over the planning horizon, the
analysis may conclude that a natural gas plant
will have a lower levelized cost than a wind
power facility. However, under a scenario that
assumes carbon costs will be imposed, the
wind facility may be the least-cost resource. If
most scenarios assume no carbon cost, the
natural gas plant will likely be the preferred
resource because it is the least-cost resource
under most potential futures, and the carbon
cost future will be viewed as an improbable
outlier. However, the scenario assuming a
carbon cost will be imposed over the planning
horizon may be more likely to occur than the
scenarios that assume no carbon price will be
imposed. In this case, the natural gas plant
might be the least-cost resource under a
variety of less-probable futures, while the
wind facility is the least-cost resource under
the most probable future. This outcome is
possible because state planning regulations
generally do not assign probabilities to future
scenarios. Least-cost planning rules may direct
utilities to assess specific scenarios, but
utilities generally have discretion to decide
whether the scenarios will actually occur
during the planning horizon. PUCs can ask
utilities to defend their assumptions, but when
there is significant uncertainty involved, PUCs
may hesitate to substitute their judgment for
that of the utilities.
Least-risk resource planning, on the other
hand, aims to prevent high-risk resources from
being selected through the planning process
by assessing a portfolio’s vulnerability to
potential risks and uncertainties across all
scenarios. In contrast to least-cost planning,
least-risk planning incorporates additional
metrics into the resource planning process to
estimate the potential for long-term cost
stability or volatility.96 Utility planners model
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A SAFE BET: LEAST-RISK RESOURCE PLANNING
for a range of specific risks and metrics, and
they may analyze resource portfolios in light
of desirable or undesirable outcomes, such as
preventing negative environmental impacts or
creating new employment opportunities.97
The following section provides a brief
overview of utility risk assessment methods.
B. ASSESSING RISK AND UNCERTAINTY
Risk assessment is the cornerstone of
least-risk resource planning. Analytical tools
and methods such as least-risk scenario
analyses enable planners to measure potential
cost impacts resulting from foreseeable yet
uncertain occurrences.98 A recent report by
the National Renewable Energy Laboratory
(NREL) notes that many states have
introduced risk parameters and least-risk
metrics into the planning process, which help
utilities identify resource portfolios that are
less vulnerable to future cost variability.99 Risk
parameters can address a variety of both
negative and beneficial impacts; for example,
planners may wish to determine the potential
environmental impacts of each candidate
portfolio or assess potential economic or
societal impacts, such as a portfolio’s potential
to create jobs in the utility’s service area.100
While it is essential for utilities to address
risk and uncertainty, accurately calculating
each portfolio’s potential risk exposure adds
significant complexity to the resource
planning process. In an attempt to simplify this
process, researchers at the Nicholas Institute
for the Environmental Policy Solutions
developed an alternative least-risk metric
designed to calculate each portfolio’s total
exposure to identified risks. In their working
paper, authors Patrick Bean and David
Hoppcock introduce a least-risk metric that
“minimizes the maximum regret” across the
range of scenarios considered in the planning
analysis.101 Under this metric, the “regret” is
the difference between a resource’s cost and
the least-cost option under the same
scenario.102 The least-cost resource under a
specific scenario would therefore have a
regret of $0. Each resource’s regret is
calculated under each scenario, and these
regrets are then added together to calculate
the resource’s “maximum regret.”103 Under
this metric, a resource that is least-cost under
a majority of scenarios may have a higher
maximum regret than alternative resources if
its costs are disproportionately high under a
specific scenario.
MINIMIZING THE
MAXIMUM REGRET
STEP 1: Calculate the net levelized cost
or present value of revenue
requirement for each resource portfolio
across all scenarios.
STEP 2: Determine the least-cost
portfolio under each scenario.
STEP 3: Determine a “regret score” for
each portfolio by subtracting the PVRR
of the least-cost portfolio under each
scenario.
STEP 4: Calculate the “maximum regret”
for each portfolio by selecting the
highest regret score for each portfolio
across all scenarios.
STEP 5: Identify the portfolio with the
lowest maximum regret.
Patrick Bean & David Hoppcock, Least-Risk Planning for
Electric Utilities (2013)
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A SAFE BET: LEAST-RISK RESOURCE PLANNING
While calculating the maximum regret for
each resource would enable utility planners to
determine each resource’s total risk exposure
under a series of scenarios, the metric treats
each scenario as equally probable, and thus
gives each scenario equal weight when
assessing total risk exposure. However, some
individual futures may have a significantly
higher probability of actually occurring than
others. By treating all scenarios as equally
probable, risk exposure determinations may
fail to account for the most realistic outcomes.
C.
One solution may be to incorporate each
scenario’s probability of occurrence into the
analysis. Oregon, for example, requires that
utility planners identify a base-case scenario
reflecting what the utility considers the most
likely future for carbon regulation.104 One
downside of this approach is that it increases
the potential for utility biases to distort the
analysis. However, PUC oversight over utility
assumptions and probability estimates may
help to minimize this distortion.
RESOURCE PLANNING RULES AND GUIDELINES
Utilities that effectively adapt to changing
circumstances in the electricity sector will be
more likely to succeed in the coming decades,
and some regulators and utility planners have
begun to consider factors beyond cost in the
planning process. A handful of states recently
amended their integrated resource planning
regulations to reflect concerns over future
environmental regulations, fuel price volatility,
market dynamics, and climate change.105
States like Arizona, Colorado, Hawaii, and
Oregon have developed methods to
incorporate least-risk planning requirements
into established resource planning models.106
Arizona’s planning rules were revised to
promote diversification of utility generation
portfolios, decrease reliance on fossil fuels,
and address environmental impacts such as air
emissions.107 Arizonan utilities now must
identify and assess a number of risks and
uncertainties and describe ways in which
these risks can be effectively managed.108 In
Colorado, the PUC recently promulgated
Resource Planning Rules that replace the term
“least-cost” with “cost-effective,” which it
defines as “the reasonableness of costs and
rate impacts in consideration of the benefits
offered by new clean energy and energyefficient technologies.”109 The rules require
utilities to include at least three alternative
resource plans in their IRPs that include more
renewable or demand-side resources than
their base portfolios.110 In general, these rules
reflect an emerging understanding that
resource investments today face potential
risks that were unforeseen twenty years ago.
Oregon provides a practical example of
how regulators can integrate least-risk
planning practices into utility resource
planning requirements. In 1989, the Oregon
PUC adopted least-cost planning as the state’s
preferred resource planning approach.111
Under this approach, the goal of resource
planning was “to ensure an adequate and
reliable supply of energy at the least cost to
the utility and its customers consistent with
the long-run public interest.”112 The Oregon
PUC subsequently revised its resource
planning requirements in 2007 to instead
direct utilities to select the portfolio “with the
best combination of expected costs and
associated risks and uncertainties.”113
Oregon’s resource planning rules include
substantive and procedural requirements to
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A SAFE BET: LEAST-RISK RESOURCE PLANNING
facilitate a least-risk planning process. From a
substantive standpoint, each resource plan
must include a variety of components, many of
which are designed to address risk and
uncertainty.114 Utilities must evaluate how
each candidate resource portfolio performs
over a range of risks and uncertainties, and
plans must include an analysis of the
uncertainties surrounding each portfolio.115 A
plan must identify any key assumptions the
utility made about the future scenarios used in
the analysis and determine whether any state
or federal energy policies could present a
barrier to the plan’s implementation.116 These
Guidelines help ensure that all reasonably
foreseeable risks and uncertainties are
addressed in the planning process and impose
a degree of accountability on utilities to
prevent improbable assumptions from guiding
the planning process. The public participation
provisions provide an additional level of
oversight and give ratepayers the opportunity
to review the risk analysis before a plan is
finalized.
Oregon’s Guidelines create a hybrid leastcost/least-risk planning regime that
encourages utilities to select portfolios with
the best balance of cost and risk, but they do
not directly require utilities to select a
portfolio that is most effective in reducing
exposure and vulnerability to risk and
uncertainty. The guidelines do help ensure
that utilities will provide the PUC with
sufficient information regarding the impacts of
risk and uncertainty on the utility’s preferred
portfolio. In addition, they enable the PUC to
reject an IRP that fails to adequately account
for risk. However, the effectiveness of these
provisions ultimately depends on how utilities
implement the guidelines during the IRP
process, and how stringently the PUC
enforces these requirements.
D. UTILITY IMPLEMENTATION OF RESOURCE PLANNING RULES
Resource planning practices and
methodologies vary considerably between
utilities, even between utilities operating
within the same jurisdiction. The manner in
which a utility implements resource planning
requirements can have a significant influence
on the composition of its preferred resource
portfolio and associated exposure to risk.
PacifiCorp and Portland General Electric’s
(PGE) 2013 IRPs help to illustrate the
variation between utility IRP practices
operating within the same jurisdiction.117 Both
utilities operate within the state of Oregon,
and thus are subject to Oregon’s IRP
Guidelines. However, the two utilities’
applications of these Guidelines differ
significantly. The two IRPs also reflect
differing assumptions about uncertain
variables and assign different probabilities to
potential outcomes. These assumptions
appeared to influence the manner in which
each utility evaluated risk and uncertainty
through the IRP process. The following
discussion describes how the two utilities
differ in implementing Oregon’s IRP
Guidelines.
PGE’s PLANNING PROCESS
Oregon’s IRP Guideline 1 directs each
utility to consider a number of sources of risk
and uncertainty.118 Guideline 4 mandates that
each IRP include an “[e]valuation of the
performance of the candidate portfolios over
the range of identified risks and
uncertainties.”119
In compliance with these directives, PGE
created a series of candidate resource
21
A SAFE BET: LEAST-RISK RESOURCE PLANNING
portfolios and evaluated these portfolios
under 36 future scenarios. These scenarios
reflected risks associated with, for example,
fuel and CO2 prices, capital costs, availability
of tax incentives, and wholesale energy
prices.120 PGE designed these future
scenarios to evaluate how reasonably
foreseeable outcomes could impact portfolio
costs.121 The utility also used stochastic
analysis, which aims to mimic real-world
variability, to address risks associated with
electricity demand and natural gas prices.122
Oregon’s IRP Guideline 1(c)(1) directs
utilities to measure both the severity and
variability of potential costs.123 In
implementing this Guideline, PGE measured
severity as the average of each candidate
portfolio’s four highest cost outcomes under
all 36 future scenarios.124 This approach aimed
to determine the highest cost, and therefore
greatest risk, each portfolio could face. To
measure variability of cost outcomes, PGE
calculated the average cost of each portfolio’s
four highest-cost futures, and then subtracted
the reference case cost (the reference case
was the future scenario PGE deemed most
likely to occur).125 This approach aimed to
determine each portfolio’s exposure to cost
risks due to external or market variables in
relation to the reference case.126 After
determining the severity and variability of
potential outcomes, PGE assessed the
durability of each portfolio by calculating the
percentage of time each portfolio would
outperform other portfolios in the individual
futures, and subtracting the percentage of
time that the portfolio would
underperform.127
Together, these cost analyses enabled PGE
to identify each resource portfolio’s exposure
to risk. First, PGE identified how specific
future variables, such as high natural gas
prices, would impact each portfolio’s cost and
performance. Second, PGE determined how
costly (i.e. risky) each portfolio could
potentially be. Third, PGE compared these
PGE’S PORTFOLIO COST AND RISK ANALYSIS
To identify the resource
portfolio with the best
combination of cost and risk,
PGE created box-andwhisker plots to measure the
highest, lowest, and
reference case outcomes for
each candidate resource
portfolio. PGE’s Figure 10-5
shows these scenario cost
outcomes for PGE’s Market
with Physical RPS candidate
portfolio. The utility then
compared these cost
distributions for all of the
2013 IRP candidate
portfolios.
PGE 2013 IRP, fig. 10-5: Candidate Portfolio Cost Detail Across All Futures, Market with
Physical RPS. Image curtesy of Portland General Electric.
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A SAFE BET: LEAST-RISK RESOURCE PLANNING
PGE’S PORTFOLIO COST AND RISK ANALYSIS: COST VARIABILITY
To measure each portfolio’s
potential cost variability, PGE
averaged each portfolio’s four
worst cost outcomes under 36
scenarios, then subtracted the
portfolio’s cost under the
reference case scenario from this
average. This measure of cost
variability provides insight into
each portfolio’s potential risk
exposure, by comparing the
difference between each
portfolio’s anticipated cost and
worst-case cost outcomes.
Portfolios with greater cost
variability have more exposure
to risk.
PGE 2013 IRP, fig. 10-3: Candidate Portfolio Risk: Average of Four Worst Outcomes
Less Reference Case (Variability). Image curtesy of Portland General Electric.
potential high-cost outcomes with the
portfolios’ costs under the most likely
outcome (the reference case). This step
essentially aimed to identify how vulnerable
each portfolio was to risk.
Finally, Oregon’s Guideline 1(c) mandates
that utilities select a resource portfolio with
the best combination of cost and risk.128 PGE
identified the three portfolios with the best
overall cost and risk performances as viable
candidates, and selected the portfolio with the
lowest estimated cost as its preferred
resource portfolio.129 PGE’s preferred
portfolio recommended adding 1,049 MW of
wind power, two 395 MW natural gas
combined cycle facilities, 463 MW of peaking
supply, 428 MW of energy efficiency, 90 MW
of demand response, and 30 MW of
dispatchable standby generation.130
PACIFICORP’S PLANNING PROCESS
PacifiCorp’s 2013 IRP followed a more
complicated approach to implementing
Oregon’s IRP Guidelines. Due to the
complexity of PacifiCorp’s methodology, a
simplified description of the key components
of the utility’s approach is introduced here.
First, the utility developed 19 input scenarios
reflecting five key variables identified by the
utility and other stakeholders: 1) CO2 prices;
2) natural gas and wholesale electricity prices;
3) policy assumptions on tax incentives and
RPS requirements; 4) policy assumptions on
coal plant compliance obligations; and 5)
energy efficiency rates.131 Next, PacifiCorp
used System Optimizer simulations to
generate resource portfolios and calculate
each portfolio’s levelized cost under each
input scenario.132 PacifiCorp then conducted
stochastic simulations for each portfolio that
randomly applied five “risk” variables: load
variation, natural gas prices, wholesale power
prices, hydro availability, and thermal unit
availability.133 To measure potential CO2
emissions compliance costs, PacifiCorp
conducted scenario analyses for zero,
medium, and high CO2 costs.134
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A SAFE BET: LEAST-RISK RESOURCE PLANNING
In implementing Guideline 1(c)(1)’s
requirement that utilities measure both cost
variability and the severity of bad cost
outcomes, PacifiCorp calculated the
stochastic average cost and risk-adjusted
average cost for each portfolio. The stochastic
average cost (which PacifiCorp called the
“stochastic mean PVRR”) is the average of each
portfolio’s variable operating costs under each
stochastic simulation, plus the portfolio’s
levelized capital and fixed costs determined by
the System Optimizer simulations.135 This
calculation represented the total potential
cost for each portfolio.136 The risk-adjusted
average cost (which PacifiCorp called the “riskadjusted mean PVRR”) aimed to incorporate the
risk of unlikely yet high-cost outcomes by
adding five percent of each portfolio’s highest
variable production cost to the portfolio’s
stochastic average cost.137
Finally, to identify a preferred resource
portfolio with the best combination of cost
and risk as required by Guideline 1(c),
PacifiCorp conducted a three-step screening
process. First, it conducted a pre-screening
that eliminated portfolios that were “clear cost
and/or risk outliers in relation to other
portfolios.”138 It then identified portfolios with
the lowest cost and risk thresholds among any
of the three CO2 price scenarios.139 In the final
screening, these top-performing portfolios
were evaluated based on risk-adjusted
average cost, CO2 emissions, and supply
reliability.140 PacifiCorp ultimately selected a
preferred resource portfolio under which the
utility will continue to rely primarily on coal
and natural gas for generating capacity.141
Their preferred portfolio recommended
adding 2,813 MW of natural gas (combined
cycle), 1,593 MW of energy efficiency, 653
MW of wind power, 362 MW of natural gas
peaking capacity, 293 MW of distributed and
10 MW of utility-scale solar power, and 193
MW of demand-side management to
PacifiCorp’s existing resource mix.142
SCENARIO DEVELOPMENT
As these descriptions illustrate, PGE and
PacifiCorp’s implementation of Oregon’s IRP
Guidelines differ significantly. The two utilities
also followed very different approaches when
developing their resource portfolios and
future scenarios.
PGE developed distinct candidate resource
portfolios to meet its future energy and
capacity needs.143 It then developed future
PACIFICORP’S CURRENT AND PROJECTED RESOURCE CAPACITY MIX, 2013 & 2022
2013 Resource Mix
Projected 2022 Resource Mix
CHP & Other
CHP & Other
Class 1 DSM +
Interruptibles
Coal (52.9%)
Class 1 DSM +
Interruptibles
Coal (43.3%)
Gas (20.2%)
Gas (25.3%)
Renewable (1.5%)
Renewable (1.3%)
Existing Purchases
Existing Purchases
Class 2 DSM
Class 2 DSM
Hydroelectric
Hydroelectric
PacifiCorp 2013 IRP, fig. 8.28: Current and Projected PacifiCorp Resource Capacity Mix for 2013 and 2022 (2013)
24
A SAFE BET: LEAST-RISK RESOURCE PLANNING
scenarios, which primarily included a single
variable, such as a high carbon price or a low
natural gas price.144 The remaining scenarios
included credible combinations of distinct
variables, such as high CO2 costs with high
natural gas costs.145 PGE then evaluated each
candidate portfolio’s performance under each
future scenario. This method allowed the
utility to build candidate portfolios based
around specific resources (such as
renewables) and assess the impacts that
individual variables (such as high carbon costs)
would have on portfolio performance. This
approach gave PGE the flexibility to decide
what kinds of resources it wanted to invest in,
and then evaluate whether these resources
would perform well and remain cost effective
under a variety of uncertain outcomes.
PacifiCorp, on the other hand, relied on its
modeling software to build its candidate
resource portfolios. The utility developed
scenarios based around general themes, in
which multiple variables were imposed
together. These scenario themes largely
reflected the utility’s underlying policy
assumptions. For example, 11 of the 19
scenarios used in the company’s 2013 IRP
were developed under an “environmental
policy” theme reflecting assumptions
regarding future environmental
regulations.146 PacifiCorp then used its
System Optimizer software to build resource
portfolios that were optimized to each
scenario’s conditions.147 In other words,
PacifiCorp decided what future conditions
might occur, and used computer software to
determine what kinds of resources would be
most cost-effective under each potential
scenario. Unlike PGE’s approach, this method
constrained PacifiCorp’s ability to select
specific resource types (such as renewables)
and evaluate their performance under
different outcomes.
POLICY ASSUMPTIONS
PGE and PacifiCorp also differed in their
assumptions regarding future energy policies,
which ultimately appeared to influence the
composition of their preferred portfolios.
In its 2013 IRP, PGE predicted that the
federal production and investment tax credits
for renewables would be renewed at their
current rates through 2023, at which time
these incentives would be replaced with a
carbon cost of $16 per ton, which would
increase by 8% a year.148 PGE’s preferred
portfolio directs the utility to add 357 MW of
new wind resources in 2020, 504 MW of wind
in 2025, and 188 MW of wind in 2030.149
In contrast, PacifiCorp’s 2013 IRP assumed
that the federal tax incentives for renewables
would be allowed to expire, and while it also
predicted that federal carbon costs of $16 a
ton would be imposed in 2022, it assumed
these costs would increase by only 3% a
year.150 During the pre-screening phase of its
scenario analysis, PacifiCorp eliminated a
portfolio developed under the assumption
that future policies would favor renewable
energy development.151 The utility rejected
the portfolio including 450 MW of new solar
PV and between 1,100 and 2,900 MW of new
wind resources152 as an improbable risk
outlier in relation to its other fossil fueldependent portfolios.153 PacifiCorp also
determined that portfolios calling for
extensive coal plant retirements were high
cost and high risk compared to portfolios with
limited or no coal plant retirements.154 Under
the utility’s preferred resource portfolio,
PacifiCorp’s renewable resource holdings will
drop from 9.9% of its total generating capacity
in 2013 to 9.3% in 2022.155
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A SAFE BET: LEAST-RISK RESOURCE PLANNING
PGE & PACIFICORP IRP ASSUMPTIONS AND WIND ENERGY ADDITIONS
Assumptions and Wind Energy
Additions
PGE
PacifiCorp
Federal Tax Incentives
Renewed through 2023
PTC expired
ITC expires in 2016
Carbon Cost
$16/ton in 2023; increasing
8% per year
$16/ton in 2022; increasing 3% per
year
Total Wind Capacity Additions
1,049 MW
650 MW
PacifiCorp’s preferred portfolio did include
an additional 432 MW of wind in 2024 and
218 MW of wind in 2025, for a total of 650
MW of new wind generation over the planning
period.156 These wind power additions
represented the minimum renewable capacity
that the utility requires to comply with its RPS
obligations.157 PacifiCorp concluded that “new
wind resource additions are not cost effective
given deteriorating policy and market
conditions.”158 These “deteriorating policy and
market conditions” included PacifiCorp’s
assumption that the federal Production Tax
Credit will not be renewed.159
PGE and PacifiCorp’s IRP scenario
modeling and portfolio selections illustrate the
extent to which a utility’s subjective
assumptions and biases may ultimately
influence its renewable resource investments.
PGE assumed that future policies will favor
renewable energy development, while
PacifiCorp assumed that future policies will
continue to support coal-fired generation. As a
result, PGE’s preferred portfolio included
nearly 400 more megawatts of wind capacity
than PacifiCorp’s preferred portfolio.160 This
portfolio variation is even more significant
given the fact that PacifiCorp is a much larger
utility, with more than three times the net
generating capacity of PGE.161
The PGE and PacifiCorp examples further
help to illustrate how separate utilities within
the same jurisdiction may implement relevant
resource planning requirements differently
from one another. These implementation
discrepancies highlight the importance of PUC
oversight during the planning process.
Oregon’s IRP Guidelines direct utilities to
balance cost and risk and to identify key
assumptions about the future.162 Both utilities
complied with this directive, but their
respective assumptions differed from one
another, particularly in regards to renewable
energy policies. The Oregon PUC must
therefore provide diligent oversight
throughout the planning process to ensure the
utilities’ assumptions are in line with the
state’s energy objectives. In general, if an IRP
does not adequately address foreseeable
sources of risk and uncertainty, the PUC
should withhold IRP acknowledgement until
the utility revises its assumptions and
analyses. PUC oversight is therefore an
essential component of least-risk planning.
As the PGE and PacifiCorp comparison
helps illustrate, the manner in which a utility
accounts for risk and uncertainty during the
planning process will likely influence the
composition of its preferred portfolio. Failure
to adequately implement risk-focused
resource planning requirements could lead a
utility to underinvest in resources that
mitigate exposure to risk, such as renewables.
Part V explores some of the potential
implications that resource planning policies
may have for renewable energy development.
26
A SAFE BET: LEAST-RISK RESOURCE PLANNING
V. F OSSIL F UELS VS . R ENEWABLE R ESOURCES :
A SSESSING R ISKS AND B ENEFITS T HROUGH
L ONG -T ERM P LANNING
Least-risk resource planning has significant
implications for renewable energy
development, primarily because renewable
resources and energy storage generally have
higher upfront costs than conventional
generation resources, yet may be less
vulnerable to foreseeable risks and potential
cost increases. Renewable energy is a valuable
addition to utility resource portfolios due to its
ability to mitigate risk and reduce vulnerability
to uncertain outcomes, including impacts
associated with rising fuel prices and future
carbon regulations. Ceres recently ranked
resources according to their relative
vulnerability to risk, and its analysis “shows a
clear division between renewable resources
and non-renewable resources,” with
renewables occupying the low-risk side of the
spectrum, and fossil fuel resources occupying
the high-risk portion.163 States and utilities
that aim to reduce exposure to risks
associated with potential carbon regulations
or fuel price increases should therefore favor
investments in renewable resources over
fossil fuel-dependent generating facilities.164
Unfortunately, regulators and utilities may
onshore wind
LOW RISK
solar pv
not fully appreciate or identify the risk
mitigation potential of renewable resource
options. Moreover, least-cost resource
planning mandates may create a barrier to
renewable energy development by preventing
utilities from investing in low-risk generation
and storage resources if the corresponding
costs are higher than alternative resources.
The explosion in natural gas extraction has led
many utilities to conclude that natural gasfired generation is the least-cost, least-risk
resource option. However, this conclusion
may fail to account for various risks and
uncertainties associated with fossil fuel
resources. The risk assessment methods and
assumptions commonly employed by utilities
during the resource planning process may
downplay some of these risks and fail to fully
account for the benefits of renewable
resources. As a result, utility resource
portfolios may be disproportionately reliant
on natural gas-fired facilities, exposing
ratepayers and investors to unnecessary risks.
This section explores the implications that
portfolio cost and risk analyses may have on
renewable resource development.
natural gas
coal
HIGH RISK
27
A SAFE BET: LEAST-RISK RESOURCE PLANNING
A. THE DANGER OF EQUATING LOW NATURAL GAS PRICES WITH
LONG-TERM RISK MITIGATION
In the late 1990s and early 2000s, state
regulators and utilities began to address the
risks associated with fossil fuel-dependent
portfolios through the resource planning
process and began to consider renewable
resources’ potential to mitigate risks
stemming from climate change and fuel price
volatility.165 During the same time period,
coal-fired power development started to
decline. According to a recent Ceres report,
“[m]ore than 120 proposals for new coal-fired
power plants have been canceled over the last
decade due to concerns about environmental
and financial risks.”166 By 2005, many western
utilities had determined that wind energy was
both a low-cost and low-risk resource, and had
committed to add significant wind energy
capacity to their existing resource
portfolios.167 Renewable energy technologies
advanced rapidly, and improvements in
manufacturing processes and increases in
production rates helped drive down costs.168
At the same time, policies such as state
renewable portfolio standards and federal tax
credits for large-scale wind and solar facilities
provided incentives for utilities to invest in
renewables. Wind power began to compete
against conventional generation resources on
a least-cost basis; for example, in 2003, Idaho
Power determined that a 100-megawatt wind
project was the least-cost resource available,
with a projected levelized cost of $33.80 per
megawatt hour over a thirty-year period.169
For a while, it appeared that the combination
of risk-oriented planning, technological
advancement, and adoption of favorable
Todd Spink, NREL (2006)
policies would hasten the transition to a
renewable electricity sector.
Then the U.S. electrical sector experienced
a fundamental shift. As it became increasingly
evident that coal would not be the fossil fuel of
choice for the 21st century, natural gas
companies greatly expanded the use of
hydraulic fracturing, or fracking, and the price
of natural gas plummeted.170 As natural gas
fuel prices dropped, the focus of utility
resource planning shifted accordingly. Utilities
appeared to equate low market prices with
reduced long-term risk, and formerly prorenewable utilities began to favor natural gas
as a low-cost alternative to coal. For example,
in its 2003 IRP, PacifiCorp noted that
renewable resources were an attractive
portfolio addition, particularly because these
28
A SAFE BET: LEAST-RISK RESOURCE PLANNING
Projected Natural Gas-Fired Generation Increases by NERC Region, 2015–2040
(million megawatt hours)
U.S. Energy Information Administration (2014)
resources could mitigate risks associated with
natural gas price volatility.171 However, in the
utility’s 2013 IRP, PacifiCorp asserted that the
“economic benefits of new renewable
resources have deteriorated,”172 and its
preferred portfolio did not include any
additional wind capacity prior to 2024.173
According to data from the U.S. Energy
Information Administration, natural gas
combined cycle (NGCC) facilities are currently
the least-cost generating resources
available,174 and are also the most commonly
constructed new fossil fuel-fired generating
facilities.175 PacifiCorp’s Preferred Portfolio,
for example, would add more than 3,000 MW
of new natural gas capacity over the 20-year
planning period, while retiring more than
2,000 MW of coal capacity.176
The boom in natural gas development
appears to correspond with a declining utility
interest in renewable resources.177 Cost
currently appears to be the primary factor
influencing most resource procurement
decisions, and many utilities appear wary of
the uncertainty surrounding future renewable
technology prices.178 Utilities further assert
that the variability and intermittency of
renewable generation make it difficult to
estimate future energy and capacity
availability, and most utilities do not include
storage in their planning models due to
insufficient data and projected expense of
existing storage technologies.179 In short,
utility resource plans now appear to favor
investments in natural gas generation due to
projections that natural gas will remain a lowcost fuel for the foreseeable future. At the
same time, utilities are avoiding investments in
significant new renewable capacity due to the
uncertainties surrounding future costs and
the availability of incentives.
The reliance on natural gas, however, may
be shortsighted. First, natural gas prices have
historically been very volatile; for example, on
November 16, 2001, day-ahead gas prices
were $1.72 per million British thermal units
(MMBtu), and on February 25, 2003, prices
were $18.41 per MMBtu.180 It is entirely
possible that this price volatility will return in
the future, particularly if U.S. exports increase
as projected, or environmental controls are
imposed on extraction activities. Second,
natural gas plants emit significant quantities of
carbon dioxide, with NGCC facilities typically
emitting between 800 and 1,000 pounds of
CO2 per MW/h,181 and these resources are
therefore vulnerable to cost increases
resulting from future carbon regulations.
29
A SAFE BET: LEAST-RISK RESOURCE PLANNING
Third, natural gas is a water-dependent form
of electricity generation, and thus is
vulnerable to potential water shortages
resulting from drought and competing
demands for limited water resources.182 And
finally, as the underlying costs and
contamination risks associated with hydraulic
fracturing come to light, jurisdictions may
impose restrictions on fracking activities. For
example, fracking generates large amounts of
waste water that developers must dispose
of.183 It recently came to light that oil and gas
developers in California had injected nearly
three billion gallons of fracking wastewater
into underground aquifers that the droughtstricken state could have used for irrigation or
drinking water.184 Concerns over
groundwater contamination such as this may
Joshua Doubek (2011)
Water tanks preparing for a fracking operation.
encourage state and local governments to
impose fracking moratoria that could reduce
fuel availability and raise prices.
The following section explores how utilities
evaluate these fossil fuel-related risks through
the resource planning process, and considers
the corresponding implications for renewable
energy development.
B. ADDRESSING FOSSIL FUEL-RELATED RISK AND UNCERTAINTY
The way in which utilities balance cost and
risk through resource planning has substantial
implications for renewable resources, which
many planners view as low-risk, yet high-cost,
generating resources.185 Fuel price volatility
and potential greenhouse gas regulation are
significant sources of risk and uncertainty for
utility resource investments, and fossil fuel
resources are particularly vulnerable to cost
increases associated with these variables.
Renewable resources have the capacity to
mitigate risks associated with rising fuel prices
or future environmental regulations.
Therefore, when utilities and regulators place
greater value on a portfolio’s risk mitigation
potential than projected cost, preferred
resource portfolios will likely include a greater
proportion of renewable generating capacity.
To fully capitalize on the mitigation potential
of renewable resources, utility planners must
effectively identify and address foreseeable
risks and uncertainties through the planning
process.
Fuel price volatility presents a significant
risk for fossil fuel-fired generating resources,
and many states direct utilities to assess fuel
price risks in their IRPs.186 However, when
utilities are allowed to pass fuel prices on to
consumers, they have little incentive to
mitigate fuel price risks.187 Indeed, when utility
planners assess natural gas fuel price impacts,
they generally appear to rely on third-party
price forecasts, which project that natural gas
prices will stay low for the foreseeable
future.188 In a 2005 report on balancing cost
and risk in utility resource plans, researchers
with the Lawrence Berkeley National
Laboratory cautioned that planners should not
overly rely on base-case natural gas price
forecasts, which have historically been
30
A SAFE BET: LEAST-RISK RESOURCE PLANNING
Trends in Natural Gas Spot Prices at Major Global Markets 2007–2011
$/MMBtu
U.S. Energy Information Administration (2011)
inaccurate.189 Instead, the authors
recommended that planners evaluate
resource portfolio performance against a wide
range of potential natural gas prices,190 and
design candidate resource portfolios to
minimize exposure to fuel price volatility.191
Moreover, regulators and public
participants cannot ensure that utilities
adequately assess fuel price volatility risks
unless utilities disclose their data. For
example, North Carolina’s IRP rules require
that utilities consider risks associated with
fuel costs,192 yet in its 2013 IRP, Duke Energy
Progress (DEP) did not provide the underlying
basis for its cost projections. In the IRP, DEP
applied the utility’s “fundamental fuel price
projections” to assess natural gas price
volatility through its portfolio analysis.193
According to the utility, these fuel cost
estimates, which were not disclosed in the IRP,
were either developed internally by the utility
or based off of “other sources.”194 It is unclear
whether the utility evaluated potential
impacts over a range of fuel prices, or if it only
assessed a single price projection. Regulatory
and public oversight over the IRP process can
help ensure that utilities are applying credible
cost projections in their risk analyses, but
effective oversight is dependent on
transparent data disclosure.
Future environmental regulation presents
another source of uncertainty for the resource
planning process. It is extremely likely that
some form of carbon regulation will be
implemented within the near future, and many
utilities now assess potential carbon
compliance requirements in their resource
plans.195 According to IRP surveys conducted
by the Regulatory Assistance Project and
Lawrence Berkeley National Laboratory,
however, methods for analyzing carbon risks
vary greatly between utilities,196 and relatively
few utilities conduct comprehensive
evaluations of potential emissions costs and
controls applicable to both existing and future
resources.197 For example, 58% of DEP’s
generating capacity consists of fossil fuel
resources,198 yet the utility’s 2013 IRP does
not assess the economic impacts that
forthcoming federal carbon emissions
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A SAFE BET: LEAST-RISK RESOURCE PLANNING
regulations may have on its existing
resources.199
Additional regulatory risks arise in the
context of water use and availability.
Generating electricity through natural gas
combustion is a water-intensive process;
natural gas extraction, processing, and
electricity generation collectively consume
hundreds of billions of gallon of fresh water
each year.200 State-imposed regulatory
constraints on natural gas-related water
consumption would have immense
implications for the industry, and some form of
controls will likely be implemented in coming
years as climate change-related water
shortages become more prevalent.201
Regulations may also be imposed to protect
drinking water supplies from contamination
resulting from natural gas extraction. Fracking
activities have reportedly contaminated fresh
groundwater in a number of states,202 and
additional regulations may be imposed to
safeguard drinking water supplies in the
future. However, few utilities appear to
evaluate risks associated with future
availability of water resources. PNM is a
notable exception. In its 2014 IRP, the New
Mexico utility conducted a drought sensitivity
analysis, which found that drought conditions
would require the utility to curtail low-cost
fossil fuel generating facilities and replace the
lost baseload generation with higher cost
wholesale energy purchases.203 This analysis is
highly relevant in arid states like New Mexico,
but many states could face potential water
shortages due to climate change.
The manner in which a utility evaluates risk
and uncertainty has significant implications for
renewable energy development. For example,
after completing the scenario analyses for its
2014 IRP, PNM concluded that potential fuel
and carbon emissions costs would largely
determine the timing of the utility’s future
renewable resource additions.204 When PNM
modeled for high natural gas and carbon costs,
the planning software added new wind energy
resources to the utility’s portfolio in 2018.205
However, when low natural gas and carbon
prices were assumed, the software did not add
new wind resources until 2029.206 This
example illustrates the impact that projected
cost inputs may have on the composition of a
utility’s preferred resource portfolio; if a utility
assumes that fuel and carbon prices will
remain low, its modeling software may
determine that renewables are not cost
effective additions to the final resource mix.
Such a conclusion, however, fails to account
for the significant risk that fuel prices or
carbon costs will rise over the course of the
planning horizon. It is therefore essential for
utilities to assess a range of credible future
conditions, and for regulators to carefully
review IRPs to ensure that the utilities’
analyses are not distorted by improbable
assumptions or inherent biases.
PNM NATURAL GAS and CARBON PRICE SCENARIO MODELING
VARIABLE
LOW SCENARIO
HIGH SCENARIO
Natural Gas Price
<$4/MMBtu (2013–2015)
$4–5/MMBtu (2016–2025)
$6/MMBtu (2026–2035)
$5/MMBtu (2013–2015)
$10/MMBtu (2016–2025)
$7–8/MMBtu (2026–2035)
Carbon Price
Federal regulation starts in 2026
$10/ton CO2 (2027)
Federal regulation starts in 2018
~$35/ton CO2 (2025)
$55/ton CO2 (2035)
Year 100 MW Wind Added
2029
2018
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A SAFE BET: LEAST-RISK RESOURCE PLANNING
C. ASSESSING RISKS AND BENEFITS OF RENEWABLE RESOURCES
The manner in which utilities address risks
and benefits associated with renewable
energy can have substantial implications for
utility investment in these resources.
However, utility treatment of renewables in
resource planning varies significantly. Utilities
attempt to predict the future cost and
performance potential of renewable
resources, and these predictions shape IRP
modeling outcomes and portfolio composition.
Renewable resource technologies introduce a
number of new variables into the planning
process, which may complicate IRP modeling
analyses. In addition, utility risk assessment
practices ultimately influence the amount of
renewable generating capacity included in a
preferred portfolio, and these analyses may be
shaped by subjective assumptions or inherent
biases that distort assigned resource values.
When utilities aim to mitigate risks associated
with fossil fuel resources and capitalize on the
benefits offered by renewable resources,
preferred resource portfolios should include a
greater percentage of renewable generating
capacity.
Utilities make varying assumptions about
the costs and availability of renewable
resources and use different processes to
develop candidate portfolios that may
influence how renewables perform through
modeling analyses.207 Cost assumptions can
significantly influence how a resource
performs through modeling and scenario
analyses, and inaccurate assumptions about
the costs associated with wind energy
integration and transmission can prevent
additional wind capacity from being seriously
considered as an available resource.208 When
utilities evaluate solar energy, their analyses
may not account for the benefits distributed
generation may provide to the grid.209
Moreover, utilities may impose arbitrary limits
on the amount of renewables included in
candidate portfolios that do not accurately
reflect the cost, performance, or risk
mitigation potential of these resources.210
Renewable energy technologies also create
a number of new variables for resource
planning, and modeling for renewable
resources may present a challenge for some
utilities. To project the levelized costs of
resources such as solar PV and wind, utilities
must address a number of unique risks and
uncertainties, including 1) the future
availability of federal and state tax incentives;
2) integration costs for both utility-scale and
UNCERTAIN COS T VARIA BLES FOR
RENEWABLE RESOURCES
•
•
•
•
•
•
federal and state tax incentives
integration costs
rate of DG deployment
capacity and load variability
back-up generation needs
technological advancements
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A SAFE BET: LEAST-RISK RESOURCE PLANNING
distributed systems; 3) rates of customersited deployment over the planning period; 4)
variability in capacity and load; 5) the need for
spinning reserves and firming generation; and
6) potential technological advancements over
the planning period that may significantly
impact the capacity of variable renewable
resources, such as widespread availability of
distributed energy storage. In addition,
external factors such as natural gas price
volatility and future environmental
regulations may have a substantial impact on
the value of renewable resources. Utilities
may be unfamiliar with collecting and
analyzing these types of data, but failing to do
so may lead to incomplete or inaccurate
projections of potential outcomes.
Moreover, the risk assessment methods
employed by utilities during the planning
process may influence the extent to which
renewables are included in the preferred
resource portfolio, yet the manner in which
utilities assess and balance the projected costs
and benefits of renewables may vary
significantly.211 Individual utilities may
evaluate different risks, or use different tools
or metrics to measure specific types of risk.212
Utilities make assumptions and predictions
about whether future policies will favor
renewable resources, and these assumptions
influence their cost projections and the
composition of their preferred resource
portfolios. Furthermore, utilities may allow
their subjective biases to influence risk
assessment through scenario analysis by
favoring results from scenarios they consider
more probable, and downplaying or ignoring
results from scenarios they consider less likely
to occur.213
Examples from PGE and Duke Energy
Progress’s 2013 IRPs help to illustrate how a
utility’s subjective policy assumptions and a
PGE’s Biglow Canyon Wind Farm in Sherman County,
Oregon. CREDIT: Tedder (2009)
state’s resource planning standards work
together to influence the renewable
generating capacity included within a
preferred resource portfolio. PGE operates in
Oregon, and thus is subject to the Oregon
PUC’s “least-cost/least-risk” IRP
Guidelines.214 As Part IV discussed, PGE’s
2013 IRP assumed that the federal production
and investment tax credits for renewables
would be renewed at their current rates
through 2023, at which time they would be
replaced with a carbon cost of $16 per ton.215
PGE’s preferred resource portfolio would add
357 MW of new wind resources in 2020, 504
MW of wind in 2025, and 188 MW of wind in
2030.216
In contrast, Duke Energy Progress (DEP)
operates in North Carolina, which imposes
both statutory and regulatory least-cost
planning requirements.217 In its 2013 IRP,
DEP determined that, absent the availability
of federal and state subsidies, solar and wind
technologies are not economically competitive
resource options.218 DEP assumed that
federal tax credits for solar will expire in 2017
and that federal subsidies for wind resources
would not likely be available in the near
future.219 Duke Energy, DEP’s parent
company, has the second-highest carbon
emissions of any electric utility in the United
States,220 yet DEP’s analysis failed to assess
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A SAFE BET: LEAST-RISK RESOURCE PLANNING
DEP’s Marshall Steam Station, a 2.09 gigawatt coal plant in Terrell, North Carolina. CREDIT: Cdtew at English Wikipedia (2013)
the benefits that additional renewable
resources could provide in mitigating risks
stemming from forthcoming federal carbon
emissions regulations.221 DEP’s preferred
portfolio would add 364 MW of new solar
resources and only 100 MW of new wind
resources through 2028.222 These additions
represent the minimum level of renewable
energy the company must obtain to comply
with its RPS obligations.223
These examples illustrate how a utility’s
subjective assumptions shape its IRP
conclusions and renewable resource
investments. In addition, the PGE and DEP
examples demonstrate how state planning
standards may influence a utility’s portfolio
composition. In North Carolina, it is state
policy “to require energy planning and fixing of
rates in a manner to result in the least cost mix
of generation and demand-reduction
measures which is achievable.”224 North
Carolina’s regulations require IRPs to identify
“the least cost combination (on a long-term
basis) of reliable resource options for meeting
the anticipated needs of its system.”225
Oregon, in contrast, directs utilities select a
resource portfolio with “the best combination
of cost and risk.”226 DEP’s overarching cost
concerns appeared to influence and restrict its
evaluation of renewable resource options.
Where regulators and utilities aim to reduce
risks associated with fossil fuel resources
(such as carbon costs) and capitalize on the
benefits associated with renewable resources
(such as tax incentives), preferred resource
portfolios should include a greater proportion
of renewable generating capacity. In contrast,
where regulators and utilities are primarily
concerned with identifying least-cost
resources, preferred portfolios include
minimal renewable capacity.
Least-risk planning policies direct utilities
to calculate risk-adjusted levelized costs, and
therefore aim to capture the value of potential
externalities that may arise over a resource’s
lifespan. Least-risk analysis helps to reduce
ratepayer and investor vulnerability to risk by
anticipating potential future cost increases.
Renewable resources, which typically have
high capital costs (although these are
declining) but low vulnerability to risk and
uncertainty, help to mitigate the fossil fuelassociated risks described in this Part.
Effective least-risk planning policies prioritize
a resource’s risk mitigation benefits and thus
help to level the playing field between
renewables and conventional energy
resources.
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A SAFE BET: LEAST-RISK RESOURCE PLANNING
VI. E STABLISHING AN E FFECTIVE L EAST -R ISK
P LANNING P OLICY
The energy sector is evolving at a rapid
pace, creating new challenges and
opportunities for electricity regulators,
utilities, and consumers. Least-risk resource
planning represents a promising energy policy
for the shifting environment of today’s
electricity sector. Utilities that adequately
seek to minimize exposure to risk and
uncertainty will be better able to adapt to the
energy realities of the 21st century. Least-risk
planning may help facilitate the transition
away from the current high-risk, fossil fueldependent electricity system, yet utilities are
generally conservative organizations and are
unlikely to alter their existing resource
planning practices on their own accord. It is
therefore up to state regulators to adopt
resource planning policies that prioritize risk
mitigation over short-term cost reduction.
Regulators can follow a series of general
steps to develop and implement effective
least-risk planning regimes. First, regulators
must review existing resource planning
regulations and revise any least-cost resource
requirements. Second, regulators must
develop least-risk planning rules establishing
threshold risk assessment parameters. Third,
regulators must effectively enforce these
planning requirements. Fourth, regulators
must connect resource plan approval to the
ratemaking process to provide some certainty
that investments in least-risk resources may
be eligible for cost recovery. This Part
explores these steps in greater detail and
provides examples from existing state
planning rules and utility IRPs to help illustrate
how regulators should apply specific planning
requirements in practice.
STEPS TO DEVELOP AN EFFECTIVE LEAST-RISK PLANNING POLICY
STEP ONE: revise least-cost resource requirements
STEP TWO: develop least-risk planning rules and guidelines
STEP THREE: implement and enforce least-risk planning rules
STEP FOUR: connect IRP approval to ratemaking process
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A. STEP 1: REVISE LEAST-COST RESOURCE REQUIREMENTS
Before a state can establish an effective
least-risk planning system, regulators must
ensure that the necessary legal foundation is
in place to enable risk-focused resource
planning. In many states, this step may entail
revising existing laws and regulations to
eliminate entrenched least-cost resource
requirements, which may directly or indirectly
prohibit resource planning practices that lead
utilities to select a non-least cost resource
portfolio. In other states, this step may
necessitate revising existing regulations to
reduce ambiguity and clarify that utilities
should identify and select resource portfolios
with less exposure to risk and uncertainty.
Some states impose least-cost
requirements through legislation,227 while
others implement least-cost requirements
through utility regulations.228 States also use
varying terminology in their resource planning
directives. Some states explicitly require
utilities to select the “least cost” resource mix,
while other states use terms like “cost
Least-cost resource requirements may dissuade
utilities from investing in renewable resources,
such as distributed solar PV systems.
effective” or “reasonable cost.” For example,
North Carolina’s regulations state that utilities
must “determine an integrated resource plan
that offers the least cost combination (on a
long-term basis) of reliable resource options
for meeting the anticipated needs of its
system.”229 New Mexico’s regulations specify
that the objective of utility resource planning
is “to identify the most cost effective portfolio
of resources to supply the energy needs of
customers.”230 Hawaii’s IRP Framework
directs utilities to provide “safe and reliable
utility service at reasonable cost.”231
The first step in establishing an effective
least-risk planning policy involves eliminating
any least-cost resource requirements within
existing laws and regulations. These revisions
should direct utility planners to identify and
select the portfolio of resources with minimal
exposure to risk and uncertainty. It is
imperative that policymakers define statutory
and regulatory terms as precisely as possible,
particularly where the terminology is open to
multiple interpretations. For example, the
term “cost effective” can be interpreted in
multiple ways, depending on the context in
which it is used. Regulatory ambiguity creates
uncertainty for utility planners, which in turn
likely encourages utilities to focus their
planning efforts on conventional resources
with a history of PUC approval. Where
statutory and regulatory texts use ambiguous
terminology, these terms should be precisely
defined to clarify that risk and uncertainty
must be considered within resource cost
calculations.
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A SAFE BET: LEAST-RISK RESOURCE PLANNING
B. STEP 2: DEVELOP LEAST-RISK PLANNING RULES
The second step in developing an effective
least-risk planning policy is to adopt and
implement least-risk planning rules that
establish requirements and parameters for
the planning process. These rules should
provide sufficient flexibility to enable planning
practices to adapt to changing circumstances,
such as new greenhouse gas regulations.
There are a number of general components
that all least-risk planning policies should
employ. These general components are
discussed briefly below, with supporting
examples from existing state IRP rules and
guidelines.
1. Establish Least-Risk Planning Goals and Objectives
Effective least-risk planning policies must
specify that the goal or objective of the
planning process is to identify a resource
portfolio that minimizes exposure to risk and
uncertainty. Oregon’s IRP Guidelines, for
example, specify that the primary goal of
integrated resource planning is to select a
resource portfolio “with the best combination
of expected costs and associated risks and
uncertainties for the utility and its
customers.”232 In addition, IRPs “must be
consistent with the long-run public
interest.”233 Regulators should clearly specify
that risk mitigation is a primary objective of
the planning process.
2. Specify Risks, Uncertainties, and Other Factors that Utilities Must Consider
Least-risk planning policies should require
that utilities identify and account for risks and
uncertainties associated with all available
resource options. The most effective policies
will require utilities to consider specific risks
identified in the planning rules, as well as
additional risks and uncertainties identified by
the utility during the planning process.
Identified risks and uncertainties that are
commonly addressed in IRP rules include risks
associated with fuel costs, wholesale energy
costs, transmission and distribution costs, and
cost of complying with environmental
regulations.234 Regulators should also direct
utilities to identify and assess any additional
risks and uncertainties that may impact a
portfolio’s long-term performance.
Some state planning rules direct utilities to
assess specific sources of risk and uncertainty.
For example, Oregon’s IRP Guideline 1
specifies that at a minimum, utilities must
address a variety of sources of risk and
uncertainty, including fuel prices, energy
prices, and “costs to comply with any
regulation of greenhouse gas emissions.”235
Guideline 8 also establishes detailed
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A SAFE BET: LEAST-RISK RESOURCE PLANNING
requirements for evaluating the potential cost
impacts of various CO2 compliance
scenarios.236 Some states direct utilities to
evaluate a portfolio’s reliance on uncertain
variables or risk mitigation potential. For
example, the New Mexico Public Regulation
Commission’s rules require utilities to assess
different resource options’ “susceptibility to
fuel interdependencies,”237 and to “consider
and describe ways to mitigate ratepayer
risk.”238 By requiring an evaluation of a
resource’s vulnerability to risk and its capacity
to minimize this exposure, regulators
encourage utilities to consider both the costs
and benefits associated with various resource
options.
Some IRP rules require utilities to consider
and evaluate additional non-cost impacts of
various resources or the resource plan itself.
For example, the Hawaii IRP Framework
requires utilities to consider the impacts that
their resource and action plans will have on
“the utility’s customers, the environment,
culture, community lifestyles, the State’s
economy, and society.”239 Under New
Mexico’s rules, utility IRPs must describe the
environmental impacts of existing supply-side
resources, including water consumption rates
and emissions rates for CO2, criteria
pollutants, and mercury.240
Requiring utilities to evaluate broader
social and environmental impacts during the
planning process should help to minimize
potential externalities that could negatively
impact public welfare on a state or regional
level. However, there are also potential
downsides to granting utilities the discretion
to consider broad, imprecise impacts, such as
conflicts with community values. For example,
a utility could potentially cite community
aesthetic concerns to justify eliminating wind
resources from its preferred portfolio. To
prevent these types of outcomes, regulators
could direct utilities to assess both local and
statewide impacts, and to balance conflicting
interests with the aim of minimizing specific
risks, such as detrimental environmental or
public health impacts. In general, planning
policies should prioritize reduced vulnerability
to foreseeable risks and should avoid defining
“risk” so broadly that utilities may avoid
evaluating certain resources for arbitrary
reasons.
3. Specify the Level of Risk Analysis Required
Least-risk planning rules should provide
guidance or parameters for the level and type
of risk analysis that utilities must conduct
during the resource planning process. Risk
modeling and analysis can be expensive and
time-consuming, and small utilities may lack
the resources to conduct complex stochastic
modeling. At a minimum, however, least-risk
planning policies should require utilities to
conduct scenario analyses to evaluate how
individual resources and resource portfolios
perform over a broad range of potential risks
and uncertainties. Regulators should also
direct utilities to describe the scenarios they
evaluate, and identify any assumptions they
make that could influence modeling outcomes.
Finally, all planning policies should establish
some procedural requirements for addressing
potential carbon risks through scenario
analyses.
Many states already require utilities to
conduct some form of scenario analysis, which
typically provides the overarching structure
for utility risk analysis. For example, Hawaii’s
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A SAFE BET: LEAST-RISK RESOURCE PLANNING
IRP Framework requires each utility to
develop a “manageable range of Scenarios”
that must “reflect possible futures dealing
with uncertain circumstances and risks facing
the utility, other stakeholders, and the utility’s
customers.”241 Oregon’s IRP Guidelines
require utilities to create a variety of resource
portfolios that represent “various operating
characteristics, resource types, fuels and
sources, technologies, lead times, in-service
dates, durations and general locations.”242
Utilities then “must evaluate how each
candidate portfolio performs over a range of
risks and uncertainties.”243 Utilities must use
at least two risk metrics to measure both cost
variability and “severity of bad outcomes,” and
utilities should include an explanation of how
their preferred portfolios “appropriately
balance cost and risk.”244 These rules direct
utilities to evaluate how different portfolios
perform under various potential outcomes,
but provide planners with the flexibility to
design their own modeling and analytical
processes.
Least-risk planning rules should require
each utility to provide a detailed description of
the scenarios it uses, an explanation of how
and why it developed the specific scenarios
accompanied by supporting data, and a
description of any underlying assumptions the
utility made regarding future outcomes or
scenarios. This information can help facilitate
regulatory and public oversight over IRP risk
analyses, by giving overseers an opportunity
to review utility predictions and assumptions
and promote consistency with public policy
goals. If a utility’s assumptions are unrealistic
or conflict with state energy objectives,
regulators then have an opportunity to
intervene and direct the utility to revise its
analyses.
A number of states currently require
utilities to identify their IRP assumptions.
These provisions may provide a useful model
for other states to follow when establishing or
revising their own planning rules. For example,
Oregon’s IRP Guidelines require utilities to
identify any “key assumptions about the future
(e.g. fuel prices and environmental compliance
costs) and alternative scenarios
considered.”245 The Hawaii IRP Framework
requires that IRPs include a full description of
“[t]he assumptions and the basis of the
assumptions underlying the Scenarios and
Resource Plans, and the key drivers of
uncertainty that may have a significant impact
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A SAFE BET: LEAST-RISK RESOURCE PLANNING
on the assumptions.”246 New Mexico’s IRP
rules list specific assumptions that utilities
must identify in their resource plans, including
assumptions regarding capital costs, operating
costs, fuel cost forecasts, and emissions
rates.247 The assumptions a utility applies to its
resource planning can significantly impact the
composition of its preferred resource
portfolio, and it is imperative that regulators
have sufficient information to identify and
evaluate these assumptions and predictions.
Regulators can help ensure the effective
implementation of least-risk planning
requirements by crafting policies with specific,
well-defined parameters that leave little room
for interpretation. These policies should
require utilities to sufficiently justify the
assumptions and probability determinations
that influence the resource compositions of
their preferred portfolios. Regulators should
also establish uniform procedures for
evaluating risks associated with fuel price
volatility and carbon regulation.
a. FUEL PRICE VOLATILITY
IRPs typically include base-case natural gas
price forecasts, which reflect anticipated fuel
prices over the planning horizon.248 These
price forecasts vary considerably among utility
IRPs.249
The U.S. Energy Information
Administration (EIA) provides both short and
long term fuel price projections. EIA’s
projections are largely based off of Henry Hub
spot market price trends.250 Regulators
seeking uniformity in IRP fuel price
forecasting could direct utilities to model their
base-case natural gas price forecasts off of
EIA’s long-term price forecast.
EIA, Annual Average Henry Hub Spot Prices for
Natural Gas in Five Cases, 1990–2040, eia.gov (2014)
In addition to spot market price curves,
utilities can also base their natural gas price
forecasts off of forward market price curves.
Forward market price curves reflect the prices
that natural gas futures are trading for on the
New York Mercantile Exchange (NYMEX).251
Researchers at LBNL concluded that forward
gas market price curves provide a good
reference point for IRP gas price forecasts,
because they may best predict future spot
market prices.252
However, natural gas price forecasts have
historically been inaccurate, and utilities
should not place too much reliance on any
base-case gas price forecasts.253 Utilities
should therefore assess how their candidate
portfolios perform under a wide range of
potential natural gas prices. Resource
planning rules should mandate that utilities
conduct scenario analyses to address a variety
of futures in which gas prices differ from
available price forecasts.
EIA’s natural gas price forecasts assess
how a number of variables may impact natural
gas prices over time. In its 2014 Annual
Energy Outlook, EIA projected how gas prices
would respond under scenarios reflecting high
and low economic growth (and thus high and
low fuel demand) and high and low oil and gas
resource availability.254 At a bare minimum,
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A SAFE BET: LEAST-RISK RESOURCE PLANNING
utility IRPs should assess how these four
scenarios would impact portfolio costs.
b. CARBON REGULATION
In a report on “Managing Carbon
Regulatory Risk in Utility Resource
Planning,”255 researchers with LBNL identified
a series of “best practices” for evaluating
carbon risks, which include modeling for
scenarios with a wide range of carbon prices,
evaluating a variety of low-carbon resource
portfolios, identifying both direct and indirect
potential effects of carbon regulation, and
effectively balancing portfolio cost and risk.256
In addition, utility plans should include a
probable carbon value in the base case
analysis or reference case portfolio, to ensure
that all portfolios are measured against a
combination of resources that adequately
reflect the changing regulatory
environment.257 Finally, utilities should assess
the implications of potential carbon
regulations on their business models as a
whole, including impacts on existing
resources, long-term power purchase
agreements, market and transmission price,
and future procurement options.258 This
analysis will enable utilities to identify their
cumulative exposure to carbon risk and
develop long-term strategies to mitigate this
risk.
Oregon’s IRP Guideline 8 establishes a
process for utilities to follow in assessing the
regulatory compliance costs they anticipate
for carbon dioxide and other air pollutants.259
Guideline 8 directs utilities to assess a series
of CO2 compliance scenarios that range from
the current regulatory level to “the upper
reaches of credible proposals by governing
entities.”260 This analysis should identify and
address upstream emissions “that would likely
EVALUATING CARBON RISKS
•
model for scenarios with wide
range of carbon prices
•
evaluate multiple low-carbon
resource portfolios
•
include a probable carbon value in
base case analysis or reference
case portfolio
•
identify potential direct and
indirect impacts of carbon
regulation
•
assess implications of carbon
regulation on business as a whole
have a significant impact” on the utilities’
resource procurement decisions.261 Guideline
8(c) directs utilities to conduct a “trigger point
analysis” in which the utility must identify a
CO2 compliance scenario that would “trigger”
the utility to select a “substantially different”
resource portfolio.262 The utility then must
develop a substitute resource portfolio to
comply with this “triggering” compliance
scenario, and compare the projected cost and
risk performance of the substitute portfolio to
that of the preferred portfolio.263 These
carbon compliance and “trigger point”
analyses help to ensure that utilities
adequately consider the carbon intensity and
vulnerability of various resource portfolios
under a range of possible regulatory futures.
Scenario analysis is an essential component
of the resource planning process because it
enables utilities to identify the impacts that
potential outcomes or uncertain variables may
have on different resources. Utilities are thus
able to identify a resource’s vulnerability to
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specific risks and uncertainties, and build
preferred portfolios that effectively mitigate
exposure to foreseeable risks. Resource
planning policies should therefore direct
utilities to conduct comprehensive scenario
analyses that evaluate the impacts from a
broad range of variables and foreseeable
outcomes. Planning rules should also require
utilities to identify and justify any assumptions
that influence the composition of a preferred
resource portfolio.
4. Require Risk-Focused Resource Ranking and Resource Selection
Least-risk planning rules should require
utilities to rank individual resource options
and resource mix portfolios on the basis of
cost and on the basis of relative exposure to
risk and vulnerability to uncertain outcomes.
For example, Oregon’s IRP Guidelines
mandate that IRPs include a ranking of
resource portfolios by both cost and risk
metrics and an interpretation of these ranking
results.264 Ranking resources based on both
their costs and exposure to risk helps to
inform the broader IRP process by ensuring
that regulators, ratepayers, and other
stakeholders are adequately informed of the
cost and risk trade-offs associated with
potential resource portfolios.
Utilities should be required to select
resource portfolios that reduce or minimize
investor, ratepayer, and taxpayer exposure to
risk. In Oregon, for example, utilities are
required to “select the portfolio that
represents the best combination of cost and
risk for the utility and its customers.”265 In
addition, resource plans should include an
explanation of a preferred resource portfolio’s
exposure to known and foreseeable risks and
vulnerability to uncertain variables. This
explanation would demonstrate to regulators
that the utilities adequately addressed and
accounted for risk and uncertainty in selecting
their preferred resource mixes. It would also
help ensure that regulators and stakeholders
are adequately informed of the risks
associated with planned resource investments
prior to IRP approval.
5. Transparency, Public Participation, and Regulatory Oversight
To ensure effective implementation, leastrisk planning rules should include provisions
requiring transparency and providing for
public participation and regulatory oversight.
Utility resource investments generally impact
three broad classes of people: 1) investors; 2)
ratepayers; and 3) members of the public.
Public participation and regulatory oversight
are therefore essential components of least-
risk planning, because they help ensure that
the diverse interests of these stakeholders are
represented and protected. Stakeholders
require access to detailed information and
data to ensure that their interests are
protected, and transparency is thus extremely
important throughout the planning process.
Public participation provisions should give
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ratepayers the opportunity to review the risk
analysis before a plan is finalized.
Some states require utilities to seek public
input throughout the planning process. In
Oregon, for example, utilities are encouraged
to allow significant public involvement in the
resource planning process and are required to
submit draft IRPs for public review and
comment.266 New Mexico’s IRP rules mandate
that utilities incorporate a public advisory
process into their IRP development to solicit
input and commentary on resource planning
and acquisition issues.267 Hawaii’s IRP
Framework requires establishment of an
Advisory Group, which aims to provide the
utility with community perspectives by
representing “diverse community,
environmental, social, political, or cultural
interests.”268 Utilities are required to consider
the group’s input, though they are not
obligated to follow the group’s
recommendations.269 Utilities are also
encouraged to convene public meetings or
forums to obtain input from individuals whose
interests may not be represented by the
Advisory Group.270
Public input may have a significant impact
on the resource planning process. PNM, New
Mexico’s largest electricity provider, was
inspired to revise its solar PV modeling
technique after receiving public input on solar
energy’s contributions to the grid.271 As a
result, PNM included additional solar PV
capacity in its preferred resource portfolio.272
PNM’s public advisory process also
encouraged the utility to update its sensitivity
analysis examining the energy impacts of
drought conditions.273 These examples
illustrate how public oversight can benefit the
planning process when utilities seriously
consider stakeholder input.
While public participation is an important
component of effective resource planning,
many utilities deny the public access to
relevant data and information regarding
resource cost projections and modeling
results. For example, in its 2013 IRP, DEP
redacted all of its resource cost projections,
screening results, and information regarding
its renewable energy purchases.274 This lack of
transparency made it extremely difficult, if not
impossible, for members of the public to
comment on the adequacy of DEP’s analyses.
After receiving stakeholder input through New Mexico’s public advisory process,
PNM revised its preferred resource portfolio to include additional solar PV capacity.
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Effective public oversight requires
transparent access to utilities’ levelized cost
projections and resource screening and
modeling results. Regulators should narrowly
construe what constitutes confidential utility
business information to ensure that the public
has access to relevant economic data, such as
levelized and avoided cost data, and cost
projections for future resource investments.
Ultimately, effective least-risk planning will
require public participation and regulatory
oversight. Regulators should therefore ensure
their rules protect these critical aspects of the
least-risk process.
C. STEP 3: IMPLEMENT AND ENFORCE LEAST-RISK PLANNING RULES
Once states adopt least-risk planning rules,
utilities and regulators must effectively
implement the planning framework with the
aim of minimizing exposure to risk and
uncertainty. Well-crafted least-risk planning
policies should minimize the potential for a
utility’s subjective assumptions to influence
the composition of its preferred portfolio.
However, these policies will work only if
utilities adequately implement the riskfocused planning requirements. Regulators
can offer guidance and direction throughout
the planning process to help facilitate effective
implementation. Ultimately, PUC enforcement
authority is the strongest mechanism in the
regulatory toolbox to ensure utilities
effectively implement planning requirements.
Therefore, the next step in establishing an
effective least-risk planning policy is to ensure
that regulators have the authority and
capacity to enforce risk assessment
requirements.
Enforcement should incorporate
regulatory oversight over the planning
process and should allow regulators to
withhold approval of resource plans that do
not adequately address potential risk or
uncertainty. This enforcement authority
should enable PUCs to withhold
acknowledgment for individual IRP
components, as well as for a complete plan.
Regulators should also have authority to
require additional analyses and revisions to
plan components or action items. For example,
if a utility fails to adequately explain or justify
its assumptions regarding future risks or
uncertainties, the PUC must have authority to
require additional analyses applying justifiable
Utilities that assume that
future conditions will follow
a business-as-usual
trajectory and assign a low
probability to conceivable
future scenarios will likely
develop resource portfolios
with less resilience to
changing circumstances.
45
A SAFE BET: LEAST-RISK RESOURCE PLANNING
future assumptions. Likewise, if a utility’s
preferred portfolio would expose ratepayers
to undue risk, the PUC should direct the utility
to revise its scenario and sensitivity analyses
and identify a portfolio with less vulnerability
to risk and uncertainty.
The PGE and PacifiCorp comparison
introduced in Part IV helps to illustrate the
importance of effective implementation and
enforcement of risk-focused planning
requirements. Part IV’s discussion explored
the different methods that the two utilities
employed in implementing Oregon’s IRP
Guidelines.275 While PacifiCorp claimed its
2013 IRP complied with Oregon’s risk
assessment requirements, its preferred
resource portfolio relied extensively on
existing coal resources and anticipated
minimal investment in renewable resources.
Part IV argued that the Oregon PUC must
provide diligent oversight to ensure that
preferred IRP portfolios will not expose
ratepayers to unreasonable risk. In regards to
PacifiCorp’s 2013 IRP, this is precisely what
the Oregon PUC did. In an order entered on
July 8, 2014, the PUC partially acknowledged
PacifiCorp’s 2013 IRP.276 In doing so,
however, the PUC required PacifiCorp to
revise certain components of the IRP and
comply with additional requirements when
preparing subsequent resource plans.277 The
PUC also refused to acknowledge one of the
IRP’s specific action items involving
investments in new pollution controls at one
of the utility’s existing coal plants.278
The PUC also indicated that it shared
stakeholder and staff concerns that
PacifiCorp’s analyses of its existing coal
resources failed to adequately account for
foreseeable costs and risks.279 In response, the
PUC directed PacifiCorp, Commission staff,
and interested stakeholders to participate in
several workshops to determine the
appropriate parameters of PacifiCorp’s coal
analyses in future IRPs.280 The PUC also
directed PacifiCorp to submit quarterly
updates on coal plant compliance
requirements, pollution control investments,
and any major capital expenditures the utility
intended to make on its existing coal plants.281
CREDIT: PDTillman (2010)
PacifiCorp owns or partially owns eleven coal-fired
power plants in five states, including the 387
megawatt Cholla coal plant in Arizona. The Oregon
PUC directed PacifiCorp to file a special update to its
2013 IRP addressing the utility’s anticipated
investments in pollution control equipment at the
plant.
The Oregon PUC’s order on PacifiCorp’s
2013 IRP illustrates how regulatory oversight
and enforcement of resource planning rules
can strengthen utility risk assessment
practices. Moreover, diligent PUC
enforcement of least-risk planning rules can
guide utilities to select resource portfolios
that mitigate ratepayer exposure to risk and
uncertainty.
46
A SAFE BET: LEAST-RISK RESOURCE PLANNING
THE HAWAIIN ELECTRIC COMPANIES’ 2013 IRP
Recent actions by the Hawaii PUC provide an
example of regulatory enforcement of utility
resource planning requirements. In 2011, the
Hawaii PUC revised its IRP rules “to allow for a
more effective, inclusive and comprehensive
planning process that acknowledges the dynamic
and constantly changing utility environment that
282
exists today.” The revised Framework consists
of an extensive list of requirements and principles
governing utility resource planning, and includes a
number of risk-focused provisions. The Framework
directs the PUC to determine whether utility plans
are in the public interest and authorizes the
commission to review and approve, reject, reject in
283
part, or require modification of the utility’s plan.
The PUC is also required to monitor the utility’s
284
implementation of an approved plan.
In April of 2014, the Hawaii PUC rejected the
Hawaiian Electric Companies’ (HECO) IRP Report
for failure to comply with the state’s IRP
285
Framework. The PUC found the IRP to be noncompliant with the Framework in a number of
ways, including its failure to provide sufficient
support for its proposed course of action over the
next five years, its failure to rank or prioritize the
final resource plans, and its failure to comply with
286
scenario planning principles.
In regards to HECO’s analytical shortcomings,
the PUC determined that HECO’s analyses failed
to “adequately demonstrate the feasibility or
accurately determine the cost of incorporating
extensive amounts of variable renewable
generation.” The utilities’ modeling techniques also
did not sufficiently assess the impacts of high
287
penetrations of variable renewables. In regards
to HECO’s failure to rank its final resource plans,
the PUC explained that the Framework’s ranking
requirement was designed to ensure transparency
in the utility’s decision-making process, which the
288
utilities failed to do.
The PUC further found that HECO had failed
to comply with the Framework’s scenario planning
provisions, which in part require the utility to
“review the Resource Plans to identify common
themes, resources, programs, and actions that
289
demonstrate robust value to costs and risks.”
The Commission characterized this provision as
“the very crux of the scenario planning concept,”
and found that HECO’s IRP contained no
discussion or analysis to clarify whether this review
290
was conducted. The PUC found that the utility
failed to sufficiently demonstrate how it evaluated
291
its resource plans to “balance cost and risk.”
On the basis of the PUC’s decision alone, it
would seem that HECO’s resource planning
practices were superficial or cursory. However,
HECO’s 2013 IRP is a 774-page document with far
more detailed and thorough analyses than the
average utility IRP. The PUC’s refusal to
acknowledge the IRP appears to be motivated in
part by the Commission’s conclusion that the
utility’s analyses failed to adequately consider the
public interest or the state’s policy goals. To
address these broader shortfalls, the PUC’s Order
included an exhibit titled, “Commission’s
Inclinations on the Future of Hawaii’s Electric
292
Utilities.” In this document, the PUC addressed
HECO’s failure to adapt to changing societal
conditions, explaining that the “IRP Action Plan
appeared to be, in part, a series of unrelated capital
projects without strategic focus on the clear issues
facing the utility, and did not indicate further
293
progress towards a sustainable business model.”
The Hawaii PUC’s decision is largely a
byproduct of the state’s energy circumstances—
Hawaii’s electricity rates are among the highest in
the country, and in many instances renewable
294
resources are the least-cost resource option.
Nevertheless, it is a compelling example of
regulatory IRP requirements, and it may be
representative of a changing tide in utility resource
planning, and perhaps electricity regulation in
general.
47
A SAFE BET: LEAST-RISK RESOURCE PLANNING
D. STEP 4: CONNECT IRP APPROVAL TO RATEMAKING
One final step in developing an effective
least-risk resource planning policy is to link
resource plan approval with utility cost
recovery. Utilities recover the value of their
resource investments through consumer
electricity rates, and most states only
authorize cost recovery for prudent
investments in resources that are used and
useful.295 States generally do not consider IRP
approval decisions to constitute
ratemaking,296 and they typically require
utilities to obtain a separate Certificate of
Convenience and Necessity (CCN) prior to
investing in new generation resources.297
However, a least-risk planning policy should
include a provision establishing that proposed
investments are presumptively prudent and
necessary so long as the resource was
identified as part of a least-risk portfolio
within an acknowledged IRP. Such a provision
would provide utilities with a degree of
certainty that they will be entitled to recover
the value of investments in least-risk
resources through the ratemaking process. It
should also provide an additional incentive for
utilities to engage in diligent resource
planning. However, this presumption of
prudence should not act as a substitute for
comprehensive ratemaking proceedings,
which allow for more thorough evaluations of
specific investment decisions.
Regulators should therefore establish both
least-risk planning and least-risk procurement
policies that together incentivize investments
in least-risk resources. These policies should
include provisions establishing a presumption
of prudence and necessity for investments in
identified least-risk resources. Once a utility
obtains a CCN to invest in a least-risk
resource, the least-risk procurement policy
should preserve the utility’s ability to recover
a portion of its costs in the event that the
resource never enters into service.
In addition to incentivizing least-risk
investments, least-risk procurement policies
should also discourage investments in leastcost resources that expose ratepayers to
excess risk or uncertainty. Procurement
policies should therefore establish a
rebuttable presumption that proposed
investments in non-least-risk resources are
not prudent or necessary. A utility could rebut
this presumption by demonstrating that the
resource would not disproportionately expose
ratepayers to risk. However, the utility would
then be subject to a strict used and useful
requirement limiting cost recovery if the
resource never entered into service or
incurred additional costs over time.
Some state IRP rules already include
provisions creating a presumption of
prudence and necessity for investments that
are consistent with an approved IRP. New
Mexico’s IRP rules, for example, establish that
when a utility seeks a CCN for a new resource,
it must provide evidence that the resource is
consistent with a commission-accepted IRP.298
New Mexico’s utilities therefore receive some
assurance that when they invest in resources
identified through the planning process, they
will be entitled to recover their investment
costs.
48
A SAFE BET: LEAST-RISK RESOURCE PLANNING
Other states consider IRP approval as a
relevant factor in ratemaking proceedings, but
stop short of allowing IRP approval to create a
rebuttable presumption of prudence and
necessity. For example, the Oregon PUC has
consistently held that IRP acknowledgment
does not constitute ratemaking, though it does
believe that IRP acknowledgment is a relevant
factor to consider when making prudence
determinations.299 According to the PUC,
“[c]onsistency with the plan may be evidence
in support of favorable rate-making treatment
of the action, although it is not a guarantee of
favorable treatment.”300 Similarly, a utility
resource investment that is inconsistent with
an acknowledged IRP will not necessarily be
denied cost recovery, though the utility must
provide additional justification for the
investment.301
The Oregon PUC’s hesitation in allowing
IRP approval to dictate ratemaking
determinations is based in part on
fundamental differences between the IRP and
ratemaking processes, particularly in regards
to access to information. In rate proceedings,
prudence determinations are “based on an
evaluation of what was known and knowable
to the utility at the time when the decision was
made.”302 If an IRP served as evidence in favor
of prudence, then ratemaking prudence
review could be based on what was known and
knowable at the time the IRP was created,
rather than at the time the investment
decision was made.303 Moreover, interested
parties have more access to information
regarding what was “knowable” to a utility
during ratemaking proceedings than they do
during the IRP process.304 During ratemaking
proceedings, interested parties have the
opportunity to conduct discovery and obtain
information on what was “known and
knowable” to the utility at the time it made the
decision to invest in a specific resource.305
Public participants in an IRP proceeding do
not have access to the same depth of
information. This is because an IRP only
outlines a utility’s anticipated resource
investments over the course of the planning
horizon, but it does not include specific
investment proposals for individual resource
acquisitions.306
As in Oregon, resource plan approvals
should not act as a substitute for prudence
determinations conducted through full
ratemaking proceedings. Nevertheless,
regulators should mandate that proposed
resource investments must be consistent with
an approved resource plan. In addition,
regulators should presume that proposed
investments in least-risk resources identified
through an approved IRP are prudent and
necessary. This presumption would provide
utilities with a degree of certainty that they
may recover the value of lower-risk
investments. In other words, regulators should
not require utilities to engage in least-risk
planning without also providing some
assurance that investments in least-risk
resources will be entitled to cost recovery.
Utilities should have some assurance
that investments in least-risk resources
will be eligible for cost recovery.
49
A SAFE BET: LEAST-RISK RESOURCE PLANNING
CONCLUSION
The electricity sector is currently
undergoing a period of substantial change, and
future conditions will almost certainly differ
dramatically from the conditions that
investor-owned utilities are accustomed to.
Though future conditions are highly uncertain
and difficult to predict, it appears inevitable
that future fuel price volatility and impending
efforts to limit greenhouse gas emissions will
make it increasingly difficult for fossil fuels to
compete in the 21st Century electricity
market. We now understand that utility
investments in fossil fuel generating resources
disproportionately expose ratepayers to
unreasonable risk, yet entrenched least-cost
planning requirements impede the transition
to a more stable, predictable energy system.
Regulators throughout the country should
therefore develop and implement least-risk
planning policies to reduce investor and
ratepayer vulnerability to risk and incentivize
renewable energy development. Utilities that
engage in least-risk planning should be better
able to adjust their procurement plans in
response to regulatory shifts and other
changes in circumstances. Perhaps more
importantly, these utilities should be better
equipped to transition from the fossil fuelbased electricity system of today to the
renewable energy system of tomorrow.
50
A SAFE BET: LEAST-RISK RESOURCE PLANNING
ENDNOTES
1
See JOHN STERLING, ET AL., NREL, TREATMENT OF SOLAR GENERATION IN ELECTRIC UTILITY RESOURCE PLANNING 4
(2013), available at http://www.nrel.gov/docs/fy14osti/60047.pdf.
2
See, e.g., FORREST SMALL & LISA FRANTZIS, THE 21ST CENTURY ELECTRIC UTILITY: POSITIONING FOR A LOW-CARBON
FUTURE, A CERES REPORT 9 (2010), available at http://www.ceres.org/resources/reports/the- 21st-centuryelectric-utility-positioning-for-a-low-carbon-future-1.
3
MELISSA POWERS, ENERGY LAW 42–43 (2012).
4
Id.
5
STERLING, ET AL., supra note 1, at 4.
6
Id. at 44.
7
See So. Cal. Edison Co. v. Pub. Util. Comm’n, 576 P.2d 945 (Cal. 1978).
8
Id.
9
Id.
10
See Duquesne Light Co. v. Barasch, 488 U.S. 299, 310–316 (1989).
11
See Melissa Powers, The Cost of Coal: Climate Change and the End of Coal as a Source of “Cheap” Electricity, 12 U.
PA. J. BUS. L. 407, 426–27 (2010).
12
Order Conditionally Approving Application of Sw. Elec. Power Co. for a Coal-Fired Power Plant in Ark. at 8,
PUC Docket No. 33891 (Tex. Pub. Util. Comm’n Aug. 12, 2008).
13
Id.
14
THE REGULATORY ASSISTANCE PROJECT, ELECTRICITY REGULATION IN THE US: A GUIDE 73 (2011), available at
http://www.google.com/url?sa=t&rct=j&q=&esrc=s&source=web&cd=1&ved=0CCgQFjAA&url=http%3A%2
F%2Fwww.raponline.org%2Fdocs%2FRAP_Lazar_ElectricityRegulationInTheUS_Guide_2011_03.pdf&ei=tq9
NU_mCDYiy2wW954GoDw&usg=AFQjCNGQmJpx6o94LjxdGMzSmrsBiezsFQ&bvm=bv.64764171,d.b2I
[hereinafter RAP GUIDE].
15
CAL. ENERGY COMM'N, COST OF GENERATION MODEL USER'S GUIDE VERSION 2 at 1–2 (2010), available at
http://www.energy.ca.gov/2010publications/CEC-200-2010-002/CEC-200-2010-002.PDF.
16
Id.
17
The revenue requirement represents the total revenue a utility must recover from consumers to recover its
costs and earn a rate of return. See Ron Davis, Group Exercise I: Calculating the Revenue Requirement,
available at
http://www.naruc.org/international/Documents/Calculating%20Revenue%20Requirement_Davis.pdf.
18
See RON BINZ, ET AL., PRACTICING RISK-AWARE ELECTRICITY REGULATION: WHAT EVERY STATE REGULATOR NEEDS
TO KNOW, A CERES REPORT 28 (April 2012), available at http://www.ceres.org/resources/reports/practicingrisk-aware-electricity-regulation.
19
See Powers, supra note 11, at 411–13.
20
Energy Policy Act of 1992, Pub. L. 102-486, 106 Stat. 2776, § 111(d)(19) (Oct. 24, 1992).
21
See RACHEL WILSON & PAUL PETERSON, SYNAPSE ENERGY ECONOMICS, A BRIEF SURVEY OF STATE INTEGRATED
RESOURCE PLANNING RULES AND REQUIREMENTS 7 (2011), available at http://www.cleanskies.org/wpcontent/uploads/2011/05/ACSF_IRP-Survey_Final_2011-04-28.pdf.
22
See, e.g., In the Matter of the Investigation into Least-Cost Planning for Resource Acquisitions by Energy
Utilities in Oregon, Order No. 89-507 (Or. Pub. Util. Comm’n Apr. 20, 1989).
23
RAP GUIDE, supra note 14, at 73.
24
See BINZ, ET AL., supra note 18, at 28.
25
POWERS, supra note 3, at 42–43.
26
Id.
27
Id. at 43.
28
Id. at 45.
29
Id. at 46.
30
Id.
31
Powers, supra note 11, at 413.
51
A SAFE BET: LEAST-RISK RESOURCE PLANNING
32
For example, during the nuclear power boom and bust of the 1970s and 1980s, many PUCs allowed utilities
to recover the costs of failed nuclear plants through electricity rates. Id. at 418–18.
33
POWERS, supra note 3, at 86.
34
See id.
35
Id. at 44.
36
Powers, supra note 11, at 417–18.
37
Id. at 418–19.
38
Id.
39
RACHEL WILSON & BRUCE BIEWALD, BEST PRACTICES IN ELECTRIC UTILITY INTEGRATED RESOURCE PLANNING 3
(2013), available at http://www.synapse-energy.com/Downloads/SynapseReport.2013-06.RAP.Best-Practicesin-IRP.13-038.pdf.
40
Id. at 3; STERLING, ET AL., supra note 1, at 1.
41
See, e.g., In the Matter of the Investigation into Least-Cost Planning for Resource Acquisitions by Energy
Utilities in Oregon, Order No. 89-507 (Or. Pub. Util. Comm’n Apr. 20, 1989).
42
STERLING, ET AL., supra note 1, at 5–6.
43
See U.S. ENERGY INFO. ADMIN., LEVELIZED COST OF NEW GENERATION RESOURCES IN THE ANNUAL ENERGY
OUTLOOK 2013, 1–5 (Jan. 2013), available at http://www.eia.gov/forecasts/aeo/pdf/electricity_generation.pdf.
44
Scenario analysis entails evaluating how a resource portfolio performs under a variety of potential future
conditions. Stochatic analysis tests portfolio performance under multiple variables that randomly change
hundreds or thousands of times. Stochastic analysis is also known as Monte Carlo simulation. Both analytical
methods aim to determine a portfolio’s sensitivity to uncertain conditions. STERLING, ET AL., supra note 1, at vi
n.4, 13.
45
MARK BOLINGER & RYAN WISER, BALANCING COST AND RISK: THE TREATMENT OF RENEWABLE ENERGY IN WESTERN
UTILITY RESOURCE PLANS 42 (2005), available at http://emp.lbl.gov/sites/all/files/REPORT%20lbnl%20%2058450_0.pdf.
46
See id.
47
Id. at 45.
48
RAP GUIDE, supra note 14, at 26.
49
POWERS, supra note 3, at 384.
50
SMALL & FRANTZIS, supra note 2, at 28.
51
Id. at 1.
52
For example, EPA recently proposed rules to regulate GHG emissions from new and existing electric
generating units. See Standards of Performance for Greenhouse Gas Emissions for New Stationary Sources:
Electric Utility Generating Units, Notice of Proposed Rulemaking, 79 FED. REG. 1,432 (Jan. 8, 2014)
[hereinafter NSPS Rule]; Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility
Generating Units, 79 FED. REG. 34,830 (June 18, 2014) [hereinafter Clean Power Plan].
53
SMALL & FRANTZIS, supra note 2, at 1.
54
Draft Survey of Utility Resource Planning and Procurement Practices for Application to Long-term
Procurement Planning in California, report prepared for the California Public Utility Commission by Aspen
Envtl. Group and Energy & Envtl. Econ., at 72 (2008), available at
http://www.cpuc.ca.gov/NR/rdonlyres/029611EA-D7C7-4ACC-84D6D6BA8515723A/0/ConsultantsReportonUtilityPlanningPracticesandAppendices09172008.pdf [hereinafter
Cal. PUC IRP Survey].
55
Id. at 73.
56
Id.
57
See id. at 85–88.
58
SMALL & FRANTZIS, supra note 2, at 17.
59
NSPS Rule, supra note 52, at 1,433.
60
ENVTL. PROTECTION AGENCY, REGULATORY IMPACT ANALYSIS FOR THE PROPOSED STANDARDS OF PERFORMANCE
FOR GREENHOUSE GAS EMISSIONS FOR NEW STATIONARY ELECTRIC UTILITY GENERATING UNITS 5-12 (2013),
available at http://www2.epa.gov/sites/production/files/2013-09/documents/20130920proposalria.pdf
[hereinafter NSPS RIA].
52
A SAFE BET: LEAST-RISK RESOURCE PLANNING
61
See id. 4-31, 5-13; see, e.g., PACIFICORP, 2013 INTEGRATED RESOURCE PLAN VOL. I at 178 (2013), available at
http://www.pacificorp.com/content/dam/pacificorp/doc/Energy_Sources/Integrated_Resource_Plan/2013IRP
/PacifiCorp-2013IRP_Vol1-Main_4-30-13.pdf [hereinafter PACIFICORP 2013 IRP].
62
Jay Warmke, Frac-Onomics: Why Fracking Makes Little Economic Sense, ECOWATCH.COM, Jan. 30, 2012,
http://ecowatch.com/2012/01/30/frac-onomics-why-fracking-makes-little-economic-sense/.
63
Id.
64
U.S. Energy Info. Admin., Natural Gas Weekly Update, Nov. 20, 2014, http://www.eia.gov/naturalgas/weekly/.
65
For example, the Energy Information Administration (EIA) anticipates that the U.S. natural gas exports will
increase substantially in the near future, exceeding eight trillion cubic feet in 2040, and predicts that natural
gas prices will increase over the coming decade due to elevated natural gas consumption and export demands.
See U.S. ENERGY INFO. ADMIN., AEO2014 EARLY RELEASE OVERVIEW 2, 7 (2014), available at
http://www.eia.gov/forecasts/aeo/er/pdf/0383er(2014).pdf.
66
See NSPS Rule, supra note 52, at 1,487.
67
See Ian Urbina, Behind Veneer, Doubt on Future of Natural Gas, NYTIMES.COM, June 26, 2011,
http://www.nytimes.com/2011/06/27/us/27gas.html.
68
Cal. PUC IRP Survey, supra note 54, at 68.
69
Id.
70
SMALL & FRANTZIS, supra note 2, at 5.
71
CARBON TRACKER INITIATIVE, UNBURNABLE CARBON 2013: WASTED CAPITAL AND STRANDED ASSETS 4 (2013),
available at http://carbontracker.live.kiln.it/Unburnable-Carbon-2-Web-Version.pdf.
72
Id.
73
SMALL & FRANTZIS, supra note 2, at 7.
74
Id. at 25.
75
Id.
76
See BINZ, ET AL., supra note 18, at 5.
77
Kenneth Colburn, et al., Least-Risk Planning, 150 NO. 11 PUB. UTIL. FORT. 38 (2012); Herman K. Trabish, Can
Decision-Makers Learn to Embrace Change in the Energy Risk Lab?, GREENTECHMEDIA.COM, Aug. 17, 2012,
http://www.greentechmedia.com/articles/read/can-decision-makers-learn-to-embrace-change-in-the-energyrisk-lab.
78
Trabish, supra note 77.
79
Colburn, et al., supra note 77, at 39.
80
Id.
81
Id.
82
Trabish, supra note 77.
83
See BOLINGER & WISER, supra note 45, at 1.
84
See STERLING, ET AL., supra note 1, at 4.
85
See PACIFICORP 2013 IRP, supra note 61, at 201.
86
See BOLINGER & WISER, supra note 45, at 1–20.
87
See id. at 1, 14, 23.
88
See Patrick Bean & David Hoppcock, Least-Risk Planning for Electric Utilities, Nicholas Institute for
Environmental Policy Solutions Working Paper 14 (2013), available at
http://nicholasinstitute.duke.edu/sites/default/files/publications/ni_wp_13-05.pdf.
89
SMALL & FRANTZIS, supra note 2, at 5 (citing MARC CHUPKA ET AL., THE BRATTLE GROUP, TRANSFORMING
AMERICA’S POWER INDUSTRY: THE INVESTMENT CHALLENGE 2010-2030 vi (2008), available at
http://www.brattle.com/_documents/UploadLibrary/Upload725.pdf).
90
See Bean & Hoppcock, supra note 88, at 4.
91
See, e.g., In the Matter of Pub. Util. Comm’n of Or.: Investigation into Integrated Resource Planning, Order
No. 07-002 at 5, n. 6 (Or. Pub. Util. Comm’n Jan. 8, 2007) (adopting integrated resource planning guidelines
directing utilities to select the “best cost/risk portfolio”).
92
BINZ, ET AL., supra note 18, at 11.
93
See WILSON & BIEWALD, supra note 39, at 5; see, e.g., PORTLAND GENERAL ELECTRIC CO., 2013 INTEGRATED
RESOURCE PLAN 187–88 (March 2014), available at
53
A SAFE BET: LEAST-RISK RESOURCE PLANNING
http://www.portlandgeneral.com/our_company/energy_strategy/resource_planning/docs/2013_irp.pdf
[hereinafter PGE 2013 IRP].
94
Bean & Hoppcock, supra note 88, at 3.
95
PGE, for example, models five different carbon dioxide compliance scenarios that impose costs ranging from
no carbon cost to $136 per short ton of CO2 emitted. PGE 2013 IRP, supra note 93, at 185.
96
STERLING, ET AL., supra note 1, at 16.
97
Id. at 17.
98
Bean & Hoppcock, supra note 88, at 5.
99
STERLING, ET AL., supra note 1, at 16.
100
Id. at 16–17.
101
Bean & Hoppcock, supra note 88.
102
Id. at 8.
103
Id.
104
Investigation into the Treatment of CO2 Risk in the Integrated Resource Planning Process, Adopted
Guideline 8, Order No. 08-339, UM 1302, app. C at 8(a) (Or. P.U.C. June 30, 2008).
105
WILSON & BIEWALD, supra note 39, at 2.
106
Id. at 4; see also STERLING, ET AL., supra note 1, at 4, 16.
107
WILSON & BIEWALD, supra note 39, at 10.
108
Id.
109
Id. at 12.
110
Id. at 13.
111
In the Matter of the Investigation into Least-Cost Planning for Resource Acquisitions by Energy Utilities in
Oregon, Order No. 89-507 (Or. Pub. Util. Comm’n Apr. 20, 1989).
112
Id. at 2.
113
Or. Pub. Util. Comm’n, Adopted IRP Guidelines, Order No. 07-047, UM 1056, app. at 2 (Or. P.U.C. Feb. 9,
2007) [hereinafter Oregon IRP Guidelines].
114
See id. Guideline 4: Plan Components.
115
Id. Guideline 4(i), (k).
116
Id. Guideline 4(g), (m).
117
See PACIFICORP 2013 IRP, supra note 61; PGE 2013 IRP, supra note 93.
118
Oregon IRP Guidelines, supra note 113, Guideline 1(b).
119
Id. Guideline 4(i).
120
PGE 2013 IRP, supra note 93, at 187.
121
Id. at 184.
122
Id. at 188.
123
Oregon IRP Guidelines, supra note 113, Guideline 1(c)(1).
124
PGE 2013 IRP, supra note 93, at 203.
125
Id.
126
Id.
127
Id. at 204.
128
Oregon IRP Guidelines, supra note 113, Guideline 1(c).
129
PGE 2013 IRP, supra note 93, at 207.
130
Id. at 176, 178. PGE ultimately determined not to recommend adding any major new supply-side resources
as part of its proposed four-year action plan, so it will reevaluate these candidate portfolios in its next IRP. Id.
131
PACIFICORP 2013 IRP, supra note 61, at 156–57, 171.
132
Id. at 185, 187. “System Optimizer” is PacifiCorp’s IRP modeling software. Id. at 159.
133
Id. at 187.
134
Id.
135
Id. at 196.
136
Id.
137
Id.
138
Id. at 199.
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A SAFE BET: LEAST-RISK RESOURCE PLANNING
139
Id.
Id. at 200.
141
Id. at 201
142
Id.
143
PGE 2013 IRP, supra note 93, at 172.
144
Id. at 184–85. It should be noted that PGE assigns differing meanings to the terms “future” and “scenario”: A
“future” is an input variable, such as a high fuel price, while a “scenario” is a future applied to a portfolio. Id. at
172.
145
Id. at 186.
146
PACIFICORP 2013 IRP, supra note 61, at 173–74.
147
Id. at 185, 187.
148
PGE 2013 IRP, supra note 93, at 103, 183.
149
Id. at 176, 178.
150
PACIFICORP 2013 IRP, supra note 61, at 167.
151
Id. at 215–216.
152
Id. at 205.
153
Id. at 201, 215–216.
154
Id. at 201.
155
Id. at 230.
156
Id. at 11.
157
Id. at 201.
158
Id. at 205.
159
Id. at 164.
160
Id. at 11; PGE 2013 IRP, supra note 93, at 176, 178.
161
PacifiCorp’s 2014 net generating capacity is 10,595 MW. PACIFICORP, PacifiCorp Facts (2014), available at
http://www.pacificorp.com/content/dam/pacificorp/doc/About_Us/Company_Overview/PC-FactSheetFinal_Web.pdf. PGE’s 2014 generating capacity is 3,376 MW. PGE 2013 IRP, supra note 93, at 20.
162
Oregon IRP Guidelines, supra note 113, Guideline 4(g).
163
BINZ, ET AL., supra note 18, at 9.
164
See BOLINGER & WISER, supra note 45, at 56.
165
Id. at 1.
166
SMALL & FRANTZIS, supra note 2, at 17.
167
BOLINGER & WISER, supra note 45, at 8.
168
SMALL & FRANTZIS, supra note 2, at 2.
169
BOLINGER & WISER, supra note 45, at 23.
170
NSPS RIA, supra note 60, at 5-12.
171
PACIFICORP, 2003 INTEGRATED RESOURCE PLAN 48 (2003), available at
http://www.pacificorp.com/content/dam/pacificorp/doc/Energy_Sources/Integrated_Resource_Plan/2003IRP
/2003IRP_Brochure_Jan2003.pdf.
172
PACIFICORP 2013 IRP, supra note 61, at 186.
173
Id. at 11.
174
U.S. ENERGY INFO. ADMIN., LEVELIZED COST OF NEW GENERATION RESOURCES IN THE ANNUAL ENERGY OUTLOOK
2013 4 (Jan. 2013), available at http://www.eia.gov/forecasts/aeo/pdf/electricity_generation.pdf.
175
NSPS Rule, supra note 52, at 1,436.
176
PACIFICORP 2013 IRP, supra note 61, at 11.
177
See, e.g., id. at 186.
178
See STERLING, ET AL., supra note 1, at vii; BOLINGER & WISER, supra note 45, at 23.
179
STERLING, ET AL., supra note 1, at 19; see, e.g., DUKE ENERGY PROGRESS, 2013 INTEGRATED RESOURCE PLAN 89
(2013), available at http://www.duke-energy.com/pdfs/dep-2013-annual-plan-public-final-r2.pdf [hereinafter
DEP 2013 IRP] (noting that energy storage technologies were eliminated from review during the IRP’s
technical screening stage).
180
PACIFICORP 2013 IRP, supra note 61, at 29.
140
55
A SAFE BET: LEAST-RISK RESOURCE PLANNING
181
See NSPS Rule, supra note 52, at 1,487.
MELISSA WHITED, FRANK ACKERMAN, & SARAH JACKSON, SYNAPSE ENERGY ECONOMICS, WATER CONSTRAINTS ON
ENERGY PRODUCTION: ALTERING OUR COLLISION COURSE 19, 29 (2013), available at http://www.synapseenergy.com/Downloads/SynapseReport.2013-06.CSI.Water-Constraints.13-010.pdf.
183
See Stephen Stock, et al., Waste Water from Oil Fracking Injected into Clean Aquifers, NBCBAYAREA.COM, Nov.
14, 2014, http://www.nbcbayarea.com/investigations/Waste-Water-from-Oil-Fracking-Injected-into-CleanAquifers-282733051.html.
184
Id.
185
BOLINGER & WISER, supra note 45, at 65.
186
See, e.g., Oregon IRP Guidelines, supra note 113, Guideline 1(B)1; N.M. Pub. Reg. Comm’n, Integrated
Resource Plans for Electric Utilities, N.M. Admin. Code § 17.7.3.9(G) (2007); N.C. Util. Comm’n, Integrated
Resource Planning and Filings, N.C.U.C. Rule R8-60(g).
187
See BOLINGER & WISER, supra note 45, at 44.
188
See, e.g., PACIFICORP 2013 IRP, supra note 61, at 178.
189
BOLINGER & WISER, supra note 45, at 48.
190
Id.
191
Id. at 54.
192
N.C. Util. Comm’n, Integrated Resource Planning and Filings, N.C.U.C. Rule R8-60(g).
193
DEP 2013 IRP, supra note 179, app. A at 42.
194
Id., app. F at 92.
195
PATRICK LUCKOW, ET AL., 2013 CARBON DIOXIDE PRICE FORECAST 17 (2013), available at http://www.synapseenergy.com/Downloads/SynapseReport.2013-11.0.2013-Carbon-Forecast.13-098.pdf.
196
BOLINGER & WISER, supra note 45, at 62.
197
WILSON & BIEWALD, supra note 39, at 30.
198
DEP 2013 IRP, supra note 179, at 32.
199
Id. at 101.
200
See Union of Concerned Scientists, How it Works: Water for Natural Gas, July 15, 2013,
http://www.ucsusa.org/clean_energy/our-energy-choices/energy-and-water-use/water-energy-electricitynatural-gas.html.
201
WHITED, ACKERMAN, & JACKSON, supra note 182, at 22–23.
202
See id. at 30–32.
203
PNM, INTEGRATED RESOURCE PLAN: 2014–2033 at 79 (July 2014), available at
https://www.pnm.com/documents/396023/396193/PNM+2014+IRP/bdccdd52-b0bc-480b-b1d6cf76c408fdfc [hereinafter PNM 2014 IRP].
204
Id. at 71.
205
Id. at 74.
206
Id.
207
See BOLINGER & WISER, supra note 45, at 1.
208
See id. at 23.
209
STERLING, ET AL., supra note 1, at 2.
210
BOLINGER & WISER, supra note 45, at 14.
211
Id. at 1, 42.
212
Id. at 42.
213
Bean & Hoppcock, supra note 88, at 5.
214
See Oregon IRP Guidelines, supra note 113.
215
PGE 2013 IRP, supra note 93, at 103, 183.
216
Id. at 176, 178.
217
N.C. GEN. STAT. § 62-2(3a); N.C. Util. Comm’n, Integrated Resource Planning and Filings, N.C.U.C. Rule R860.
218
DEP 2013 IRP, supra note 179, at 92.
219
Id. at 5, 19–20.
182
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A SAFE BET: LEAST-RISK RESOURCE PLANNING
220
CHRISTOPHER E. VAN ATTEN, ET AL., BENCHMARKING AIR EMISSIONS OF THE 100 LARGEST ELECTRIC POWER
PRODUCERS IN THE UNITED STATES 34 (May 2014), available at
http://www.nrdc.org/air/pollution/benchmarking/files/benchmarking-2014.pdf.
221
The U.S. Environmental Protection Agency (EPA) recently proposed two rules that would regulate carbon
emissions from new and existing stationary electricity generating units. NSPS Rule, supra note 52; Clean Power
Plan, supra note 52.
222
DEP 2013 IRP, supra note 179, at 18.
223
Id. at 17.
224
N.C. Gen. Stat. § 62-2(3a).
225
N.C. Util. Comm’n, Integrated Resource Planning and Filings, N.C.U.C. Rule R8-60(g) (emphasis added).
226
Oregon IRP Guidelines, supra note 113, Guideline 1(c).
227
For example, North Carolina’s general statute states that it is “the policy of the State of North Carolina . . . to
require energy planning and fixing of rates in a manner to result in the least cost mix of generation and demandreduction measures which is achievable.” N.C. Gen. Stat. § 62-2(3a).
228
In Oregon, for example, the PUC’s IRP Guidelines states that the primary goal of resource planning “must be
the selection of a portfolio of resources with the best combination of expected costs and associated risks and
uncertainties for the utility and its customers.” Oregon IRP Guidelines, supra note 113, Guideline 1(c).
229
N.C. Util. Comm’n, Integrated Resource Planning and Filings, N.C.U.C. Rule R8-60(g) (emphasis added).
230
N.M. Pub. Reg. Comm’n, Integrated Resource Plans for Electric Utilities, N.M. Admin. Code § 17.7.3.6
(2007) (emphasis added).
231
Haw. Pub. Util. Comm’n, A Framework for Integrated Resource Planning § II.A (March 14, 2011)
[hereinafter Haw. IRP Framework].
232
Oregon IRP Guidelines, supra note 113, Guideline 1(c).
233
Id. Guideline 1(d).
234
See, e.g., N.C.U.C. Rule R8-60(e); N.M. ADMIN. CODE § 17.7.3.9(G)(1); Oregon IRP Guidelines, supra note
113, Guideline 1(b).
235
Oregon IRP Guidelines, supra note 113, Guideline 1(b).
236
Investigation into the Treatment of CO2 Risk in the Integrated Resource Planning Process, Adopted
Guideline 8, Order No. 08-339, UM 1302, app. C (Or. P.U.C. June 30, 2008).
237
N.M. ADMIN. CODE § 17.7.3.9(G)(2).
238
Id. § 17.7.3.9(G)(1).
239
Haw. IRP Framework, supra note 231, § II.B.4.
240
N.M. ADMIN. CODE § 17.7.3.9(C)(12).
241
Haw. IRP Framework, supra note 231, § V.C.8(a).
242
Oregon IRP Guidelines, supra note 113, Guideline 4(h).
243
Id. Guideline 4(i).
244
Id. Guideline 1(c).
245
Id. Guideline 4(g).
246
Haw. IRP Framework, supra note 231, § IV.D.1(a)(3).
247
N.M. ADMIN. CODE § 17.7.3.9(F)(1).
248
BOLINGER & WISER, supra note 45, at 44.
249
Id.
250
See U.S. ENERGY INFO. ADMIN., ANNUAL ENERGY OUTLOOK 2014 (2014), available at
http://www.eia.gov/forecasts/aeo/pdf/0383(2014).pdf.
251
See U.S. ENERGY INFO. ADMIN., AN ASSESSMENT OF PRICES OF NATURAL GAS FUTURES CONTRACTS AS A
PREDICTOR OF REALIZED SPOT PRICES AT THE HENRY HUB (2005), available at
http://www.eia.gov/pub/oil_gas/natural_gas/feature_articles/2005/futures/futures.pdf.
252
BOLINGER & WISER, supra note 45, at 47.
253
Id. at 48.
254
U.S. ENERGY INFO. ADMIN., ANNUAL ENERGY OUTLOOK 2014 MT-21, MT-22 (2014), available at
http://www.eia.gov/forecasts/aeo/pdf/0383(2014).pdf.
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255
GALEN BARBOSE, ET AL., MANAGING CARBON REGULATORY RISK IN UTILITY RESOURCE PLANNING: CURRENT
PRACTICES IN THE WESTERN UNITED STATES (2009), available at
http://emp.lbl.gov/sites/all/files/Managing%20Carbon%20Regulatory%20Risk%20in%20Utility%20Resource
%20Planning%20Current%20Practices%20in%20the%20Western%20United%20States.pdf.
256
Id. at 16; see also SMALL & FRANTZIS, supra note 2, at 8–9.
257
See BOLINGER & WISER, supra note 45, at 62–63.
258
See SMALL & FRANTZIS, supra note 2, at 10.
259
Oregon IRP Guidelines, supra note 113, Guideline 8.
260
Id. Guideline 8(a).
261
Id.
262
Id. Guideline 8(c).
263
Id.
264
Id. Guideline 4(j).
265
Id. Guideline 4(l).
266
Id. Guideline 2.
267
N.M. ADMIN. CODE § 17.7.3.9.H.
268
Haw. IRP Framework, supra note 231, § III.F.1.
269
Id. § III.F.3.
270
Id. § III.G.2.
271
PNM 2014 IRP, supra note 203, at 112.
272
Id.
273
Id.
274
DEP 2013 IRP, supra note 179, at 93–95, 150–153.
275
See discussion supra section IV.D.
276
In the Matter of PacifiCorp, dba Pacific Power, 2013 Integrated Resource Plan, Order No. 14-252 (Or.
P.U.C. Jul. 8, 2014).
277
Id.
278
Id. at 7.
279
Id. at 4–5.
280
Id. at 5.
281
Id. at 3.
282
In re Pub. Util. Comm’n: Instituting a Proceeding to Investigate Proposed Amendments to the Framework
for Integrated Resource Planning, Docket No. 2009-0108 at 2 (Haw. P.U.C. March 14, 2011).
283
Haw. IRP Framework, supra note 231, § III.A (2011).
284
Id.
285
In re Pub. Util. Comm’n: Regarding Integrated Resource Planning, Order No. 32052 (Haw. P.U.C. April 28,
2014).
286
Id. at 22.
287
Id. at 27.
288
Id. at 33.
289
Id. at 36.
290
Id.
291
Id. at 39.
292
Id. at Exhibit A.
293
Id. at 1.
294
See id. at 2.
295
See POWERS, supra note 3, at 115–16.
296
See In re PacifiCorp, dba Pacific Power, 2013 Integrated Resource Plan, Order No. 14-252 at 1 (Or. P.U.C.
Jul. 8, 2014).
297
See POWERS, supra note 3, at 45.
298
Integrated Resource Plans for Electric Utilities, N.M. ADMIN. CODE § 17.7.3.12 (2007).
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A SAFE BET: LEAST-RISK RESOURCE PLANNING
299
See In re Pub. Util. Comm’n of Or.: Investigation into Integrated Resource Planning, Order No. 07-002 at 24
(Or. P.U.C. Jan. 8, 2007); In re Investigation into Least-Cost Planning for Resource Acquisitions by Energy
Utilities in Oregon, Order No. 89-507 at 7 (Or. P.U.C. Apr. 20, 1989).
300
Or. P.U.C. Order 07-002 at 24 (Jan. 8, 2007) (quoting Or. P.U.C. Order No. 89-507 at 7 (Apr. 20, 1989)).
301
Id.
302
Id. at 25.
303
Id.
304
Id.
305
Id.
306
Id.
59